Cogeneration systems and processes for treating hydrocarbon containing formations

ABSTRACT

A system for treating a hydrocarbon containing formation includes a steam and electricity cogeneration facility. At least one injection well is located in a first portion of the formation. The injection well provides steam from the steam and electricity cogeneration facility to the first portion of the formation. At least one production well is located in the first portion of the formation. The production well in the first portion produces first hydrocarbons. At least one electrical heater is located in a second portion of the formation. At least one of the electrical heaters is powered by electricity from the steam and electricity cogeneration facility. At least one production well is located in the second portion of the formation. The production well in the second portion produces second hydrocarbons. The steam and electricity cogeneration facility uses the first hydrocarbons and/or the second hydrocarbons to generate electricity.

PRIORITY CLAIM

This patent application claims priority to U.S. Provisional Patent No.60/729,763 entitled “SYSTEMS AND PROCESSES FOR USE IN TREATINGSUBSURFACE FORMATIONS” to Vinegar et al. filed on Oct. 24, 2005; and toU.S. Provisional Patent No. 60/794,298 entitled “SYSTEMS AND PROCESSESFOR USE IN TREATING SUBSURFACE FORMATIONS” to Vinegar et al. filed onApr. 21, 2006.

GOVERNMENT INTEREST

The Government has certain rights in this invention pursuant toAgreement No. ERD-05-2516 between UT-Battelle, LLC, operating underprime contract No. DE-ACO5-00OR22725 for the US Department of Energy andShell Exploration and Production Company.

RELATED PATENTS

This patent application incorporates by reference in its entirety eachof U.S. Pat. No. 6,688,387 to Wellington et al.; U.S. Pat. No. 6,991,036to Sumnu-Dindoruk et al.; U.S. Pat. No. 6,698,515 to Karanikas et al.;U.S. Pat. No. 6,880,633 to Wellington et al.; U.S. Pat. No. 6,782,947 tode Rouffignac et al; U.S. Pat. No. 6,991,045 to Vinegar et al.; U.S.Pat. No. 7,073,578 to Vinegar et al.; and U.S. Pat. No. 7,121,342 toVinegar et al. This patent application incorporates by reference in itsentirety U.S. Patent Application Publication 2005-0269313 to Vinegar etal. This patent application incorporates by reference in its entiretyU.S. patent application Ser. No. 11/409,558 to Vinegar et al.

BACKGROUND

1. Field of the Invention

The present invention relates generally to methods and systems forproduction of hydrocarbons, hydrogen, and/or other products from varioussubsurface formations such as hydrocarbon containing formations. Certainembodiments relate to using a steam and electricity cogenerationfacility in combination with steam injection recovery and in situprocessing of a hydrocarbon containing formation.

2. Description of Related Art

Hydrocarbons obtained from subterranean formations are often used asenergy resources, as feedstocks, and as consumer products. Concerns overdepletion of available hydrocarbon resources and concerns over decliningoverall quality of produced hydrocarbons have led to development ofprocesses for more efficient recovery, processing and/or use ofavailable hydrocarbon resources. In situ processes may be used to removehydrocarbon materials from subterranean formations. Chemical and/orphysical properties of hydrocarbon material in a subterranean formationmay need to be changed to allow hydrocarbon material to be more easilyremoved from the subterranean formation. The chemical and physicalchanges may include in situ reactions that produce removable fluids,composition changes, solubility changes, density changes, phase changes,and/or viscosity changes of the hydrocarbon material in the formation. Afluid may be, but is not limited to, a gas, a liquid, an emulsion, aslurry, and/or a stream of solid particles that has flow characteristicssimilar to liquid flow.

A wellbore may be formed in a formation. In some embodiments wellboresmay be formed using reverse circulation drilling methods. Reversecirculation methods are suggested, for example, in published U.S. PatentApplication Publication No. 2004-0079553 to Livingstone, and U.S. Pat.No. 6,854,534 to Livingstone; U.S. Pat. No. 6,892,829 to Livingstone,U.S. Pat. No. 7,090,018 to Livingstone; and U.S. Pat. No. 4,823,890 toLang, the disclosures of which are incorporated herein by reference.Reverse circulation methods generally involve circulating a drillingfluid to a drilling bit through an annulus between concentric tubularsto the borehole in the vicinity of the drill bit, and then throughopenings in the drill bit and to the surface through the center of theconcentric tubulars, with cuttings from the drilling being carried tothe surface with the drilling fluid rising through the center tubular. Awiper or shroud may be provided above the drill bit and above a pointwhere the drilling fluid exits the annulus to prevent the drilling fluidfrom mixing with formation fluids. The drilling fluids may be, but isnot limited to, air, water, brines and/or conventional drilling fluids.

In some embodiments, a casing or other pipe system may be placed orformed in a wellbore. U.S. Pat. No. 4,572,299 issued to Van Egmond etal., which is incorporated by reference as if fully set forth herein,describes spooling an electric heater into a well. In some embodiments,components of a piping system may be welded together. Quality of formedwells may be monitored by various techniques. In some embodiments,quality of welds may be inspected by a hybrid electromagnetic acoustictransmission technique known as EMAT. EMAT is described in U.S. Pat. No.5,652,389 to Schaps et al.; U.S. Pat. No. 5,760,307 to Latimer et al.;U.S. Pat. No. 5,777,229 to Geier et al.; and U.S. Pat. No. 6,155,117 toStevens et al., each of which is incorporated by reference as if fullyset forth herein.

In some embodiments, an expandable tubular may be used in a wellbore.Expandable tubulars are described in U.S. Pat. No. 5,366,012 to Lohbeck,and U.S. Pat. No. 6,354,373 to Vercaemer et al., each of which isincorporated by reference as if fully set forth herein.

Heaters may be placed in wellbores to heat a formation during an in situprocess. Examples of in situ processes utilizing downhole heaters areillustrated in U.S. Pat. No. 2,634,961 to Ljungstrom; U.S. Pat. No.2,732,195 to Ljungstrom; U.S. Pat. No. 2,780,450 to Ljungstrom; U.S.Pat. No. 2,789,805 to Ljungstrom; U.S. Pat. No. 2,923,535 to Ljungstrom;and U.S. Pat. No. 4,886,118 to Van Meurs et al.; each of which isincorporated by reference as if fully set forth herein.

Application of heat to oil shale formations is described in U.S. Pat.No. 2,923,535 to Ljungstrom and U.S. Pat. No. 4,886,118 to Van Meurs etal. Heat may be applied to the oil shale formation to pyrolyze kerogenin the oil shale formation. The heat may also fracture the formation toincrease permeability of the formation. The increased permeability mayallow formation fluid to travel to a production well where the fluid isremoved from the oil shale formation. In some processes disclosed byLjungstrom, for example, an oxygen containing gaseous medium isintroduced to a permeable stratum, preferably while still hot from apreheating step, to initiate combustion.

A heat source may be used to heat a subterranean formation. Electricheaters may be used to heat the subterranean formation by radiationand/or conduction. An electric heater may resistively heat an element.U.S. Pat. No. 2,548,360 to Germain, which is incorporated by referenceas if fully set forth herein, describes an electric heating elementplaced in a viscous oil in a wellbore. The heater element heats andthins the oil to allow the oil to be pumped from the wellbore. U.S. Pat.No. 4,716,960 to Eastlund et al., which is incorporated by reference asif fully set forth herein, describes electrically heating tubing of apetroleum well by passing a relatively low voltage current through thetubing to prevent formation of solids. U.S. Pat. No. 5,065,818 to VanEgmond, which is incorporated by reference as if fully set forth herein,describes an electric heating element that is cemented into a wellborehole without a casing surrounding the heating element.

U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporated byreference as if fully set forth herein, describes an electric heatingelement that is positioned in a casing. The heating element generatesradiant energy that heats the casing. A granular solid fill material maybe placed between the casing and the formation. The casing mayconductively heat the fill material, which in turn conductively heatsthe formation.

U.S. Pat. No. 4,570,715 to Van Meurs et al., which is incorporated byreference as if fully set forth herein, describes an electric heatingelement. The heating element has an electrically conductive core, asurrounding layer of insulating material, and a surrounding metallicsheath. The conductive core may have a relatively low resistance at hightemperatures. The insulating material may have electrical resistance,compressive strength, and heat conductivity properties that arerelatively high at high temperatures. The insulating layer may inhibitarcing from the core to the metallic sheath. The metallic sheath mayhave tensile strength and creep resistance properties that arerelatively high at high temperatures.

U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement having a copper-nickel alloy core.

Obtaining permeability in an oil shale formation between injection andproduction wells tends to be difficult because oil shale is oftensubstantially impermeable. Many methods have attempted to link injectionand production wells. These methods include: hydraulic fracturing suchas methods investigated by Dow Chemical and Laramie Energy ResearchCenter; electrical fracturing by methods investigated by Laramie EnergyResearch Center; acid leaching of limestone cavities by methodsinvestigated by Dow Chemical; steam injection into permeable nahcolitezones to dissolve the nahcolite by methods investigated by Shell Oil andEquity Oil; fracturing with chemical explosives by methods investigatedby Talley Energy Systems; fracturing with nuclear explosives by methodsinvestigated by Project Bronco; and combinations of these methods. Manyof these methods, however, have relatively high operating costs and lacksufficient injection capacity.

Large deposits of heavy hydrocarbons (heavy oil and/or tar) contained inrelatively permeable formations (for example in tar sands) are found inNorth America, South America, Africa, and Asia. Tar can be surface-minedand upgraded to lighter hydrocarbons such as crude oil, naphtha,kerosene, and/or gas oil. Surface milling processes may further separatethe bitumen from sand. The separated bitumen may be converted to lighthydrocarbons using conventional refinery methods. Mining and upgradingtar sand is usually substantially more expensive than producing lighterhydrocarbons from conventional oil reservoirs.

In situ production of hydrocarbons from tar sand may be accomplished byheating and/or injecting a gas into the formation. U.S. Pat. No.5,211,230 to Ostapovich et al. and U.S. Pat. No. 5,339,897 to Leaute,which are incorporated by reference as if fully set forth herein,describe a horizontal production well located in an oil-bearingreservoir. A vertical conduit may be used to inject an oxidant gas intothe reservoir for in situ combustion.

U.S. Pat. No. 2,780,450 to Ljungstrom describes heating bituminousgeological formations in situ to convert or crack a liquid tar-likesubstance into oils and gases. U.S. Pat. No. 4,597,441 to Ware et al.,which is incorporated by reference as if fully set forth herein,describes contacting oil, heat, and hydrogen simultaneously in areservoir. Hydrogenation may enhance recovery of oil from the reservoir.U.S. Pat. No. 5,046,559 to Glandt and U.S. Pat. No. 5,060,726 to Glandtet al., which are incorporated by reference as if fully set forthherein, describe preheating a portion of a tar sand formation between aninjector well and a producer well. Steam may be injected from theinjector well into the formation to produce hydrocarbons at the producerwell.

As outlined above, there has been a significant amount of effort todevelop methods and systems to economically produce hydrocarbons,hydrogen, and/or other products from hydrocarbon containing formations.At present, however, there are still many hydrocarbon containingformations from which hydrocarbons, hydrogen, and/or other productscannot be economically produced. Thus, there is still a need forimproved methods and systems for production of hydrocarbons, hydrogen,and/or other products from various hydrocarbon containing formations.

SUMMARY

Embodiments described herein generally relate to systems, methods, andheaters for treating a subsurface formation. Embodiments describedherein also generally relate to heaters that have novel componentstherein. Such heaters can be obtained by using the systems and methodsdescribed herein.

In certain embodiments, the invention provides one or more systems,methods, and/or heaters. In some embodiments, the systems, methods,and/or heaters are used for treating a subsurface formation.

In certain embodiments, the invention provides a system for treating ahydrocarbon containing formation, comprising: a steam and electricitycogeneration facility; at least one injection well located in a firstportion of the formation, the injection well configured to provide steamfrom the steam and electricity cogeneration facility to the firstportion of the formation; at least one production well located in thefirst portion of the formation, the production well configured toproduce first hydrocarbons; at least one electrical heater located in asecond portion of the formation, at least one of the electrical heatersconfigured to be powered by electricity from the steam and electricitycogeneration facility; at least one production well located in thesecond portion of the formation, the production well configured toproduce second hydrocarbons; and the steam and electricity cogenerationfacility configured to use the first hydrocarbons and/or the secondhydrocarbons to generate electricity.

In certain embodiments, the invention provides a method for treating ahydrocarbon containing formation, comprising: providing steam to a firstportion of the formation; producing first hydrocarbons from the firstportion of the formation; providing heat from one or more electricalheaters to a second portion of the formation; allowing the provided heatto transfer from the heaters to the second portion of the formation;producing second hydrocarbons from the second portion of the formation;and using the first hydrocarbons and/or the second hydrocarbons in asteam and electricity generation facility, wherein the facility providessteam to the first portion of the formation and electricity for at leastsome of the heaters.

In certain embodiments, the invention provides a method for treating ahydrocarbon containing formation, comprising: providing steam to a firstportion of the formation; providing heat from one or more electricalheaters to the first portion of the formation; producing firsthydrocarbons and/or second hydrocarbons from the first portion of theformation; providing heat from one or more electrical heaters to asecond portion of the formation; allowing the provided heat to transferfrom the heaters to the second portion of the formation; producingsecond hydrocarbons from the second portion of the formation; and usingthe first hydrocarbons and/or the second hydrocarbons in a steam andelectricity generation facility, wherein the facility provides steam tothe first portion of the formation and electricity for at least some ofthe heaters.

In certain embodiments, the invention provides a method for treating ahydrocarbon containing formation, comprising: providing steam to a firstportion of the formation; producing first hydrocarbons from the firstportion of the formation; providing heat from one or more electricalheaters to a second portion of the formation; allowing the provided heatto transfer from the heaters to the second portion of the formation;providing steam to the second portion of the formation; producing firsthydrocarbons and/or second hydrocarbons from the second portion of theformation; and using the first hydrocarbons and/or the secondhydrocarbons in a steam and electricity generation facility, wherein thefacility provides steam to the first portion or the second portion ofthe formation and electricity for at least some of the heaters.

In further embodiments, features from specific embodiments may becombined with features from other embodiments. For example, featuresfrom one embodiment may be combined with features from any of the otherembodiments. In further embodiments, treating a subsurface formation isperformed using any of the methods, systems, or heaters describedherein. In further embodiments, additional features may be added to thespecific embodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

Advantages of the present invention may become apparent to those skilledin the art with the benefit of the following detailed description andupon reference to the accompanying drawings in which:

FIG. 1 depicts an illustration of stages of heating a hydrocarboncontaining formation.

FIG. 2 shows a schematic view of an embodiment of a portion of an insitu heat treatment system for treating a hydrocarbon containingformation.

FIG. 3 depicts a schematic of an embodiment of a Kalina cycle forproducing electricity.

FIG. 4 depicts a schematic of an embodiment of a Kalina cycle forproducing electricity.

FIG. 5 depicts a schematic representation of an embodiment of a systemfor producing pipeline gas.

FIG. 6 depicts a schematic representation of an embodiment of a systemfor producing pipeline gas.

FIG. 7 depicts a schematic representation of an embodiment of a systemfor producing pipeline gas.

FIG. 8 depicts a schematic representation of an embodiment of a systemfor producing pipeline gas.

FIG. 9 depicts a schematic representation of an embodiment of a systemfor producing pipeline gas.

FIG. 10 depicts a schematic representation of an embodiment of a systemfor treating the mixture produced from the in situ heat treatmentprocess.

FIG. 11 depicts a schematic representation of an embodiment of a systemfor treating a liquid stream produced from an in situ heat treatmentprocess.

FIG. 12 depicts a schematic drawing of an embodiment of areverse-circulating polycrystalline diamond compact drill bit design.

FIG. 13 depicts a schematic drawing of an embodiment of a drillingsystem.

FIG. 14 depicts a schematic drawing of an embodiment of a drillingsystem for drilling into a hot formation.

FIG. 15 depicts a schematic drawing of an embodiment of a drillingsystem for drilling into a hot formation.

FIG. 16 depicts a schematic drawing of an embodiment of a drillingsystem for drilling into a hot formation.

FIG. 17 depicts an embodiment of a freeze well for a circulated liquidrefrigeration system, wherein a cutaway view of the freeze well isrepresented below ground surface.

FIG. 18A depicts an embodiment of a wellbore for introducing wax into aformation to form a wax grout barrier.

FIG. 18B depicts a representation of a wellbore drilled to anintermediate depth in a formation.

FIG. 18C depicts a representation of the wellbore drilled to the finaldepth in the formation.

FIG. 19 depicts an embodiment of a ball type reflux baffle systempositioned in a heater well.

FIG. 20 depicts an embodiment of a device for longitudinal welding of atubular using ERW.

FIGS. 21, 22, and 23 depict cross-sectional representations of anembodiment of a temperature limited heater with an outer conductorhaving a ferromagnetic section and a non-ferromagnetic section.

FIGS. 24, 25, 26, and 27 depict cross-sectional representations of anembodiment of a temperature limited heater with an outer conductorhaving a ferromagnetic section and a non-ferromagnetic section placedinside a sheath.

FIGS. 28A and 28B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 29A and 29B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 30A and 30B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 31A and 31B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 32A and 32B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIG. 33 depicts a cross-sectional representation of an embodiment of acomposite conductor with a support member.

FIG. 34 depicts a cross-sectional representation of an embodiment of acomposite conductor with a support member separating the conductors.

FIG. 35 depicts a cross-sectional representation of an embodiment of acomposite conductor surrounding a support member.

FIG. 36 depicts a cross-sectional representation of an embodiment of acomposite conductor surrounding a conduit support member.

FIG. 37 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit heat source.

FIG. 38 depicts a cross-sectional representation of an embodiment of aremovable conductor-in-conduit heat source.

FIG. 39 depicts an embodiment of a temperature limited heater in whichthe support member provides a majority of the heat output below theCurie temperature of the ferromagnetic conductor.

FIGS. 40 and 41 depict embodiments of temperature limited heaters inwhich the jacket provides a majority of the heat output below the Curietemperature of the ferromagnetic conductor.

FIG. 42 depicts a high temperature embodiment of a temperature limitedheater.

FIG. 43 depicts hanging stress versus outside diameter for thetemperature limited heater shown in FIG. 39 with 347H as the supportmember.

FIG. 44 depicts hanging stress versus temperature for several materialsand varying outside diameters of the temperature limited heater.

FIGS. 45, 46, 47, and 48 depict examples of embodiments for temperaturelimited heaters that vary the materials and/or dimensions along thelength of the heaters to provide desired operating properties.

FIGS. 49 and 50 depict examples of embodiments for temperature limitedheaters that vary the diameter and/or materials of the support memberalong the length of the heaters to provide desired operating propertiesand sufficient mechanical properties.

FIGS. 51A and 51B depict cross-sectional representations of anembodiment of a temperature limited heater component used in aninsulated conductor heater.

FIGS. 52A and 52B depict an embodiment of a system for installingheaters in a wellbore.

FIG. 52C depicts an embodiment of an insulated conductor with the sheathshorted to the conductors.

FIG. 53 depicts an embodiment for coupling together sections of a longtemperature limited heater.

FIG. 54 depicts an embodiment of a shield for orbital welding sectionsof a long temperature limited heater.

FIG. 55 depicts a schematic representation of an embodiment of a shutoff circuit for an orbital welding machine.

FIG. 56 depicts an embodiment of a temperature limited heater with a lowtemperature ferromagnetic outer conductor.

FIG. 57 depicts an embodiment of a temperature limitedconductor-in-conduit heater.

FIG. 58 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater.

FIG. 59 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater.

FIG. 60 depicts a cross-sectional view of an embodiment of aconductor-in-conduit temperature limited heater.

FIG. 61 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor.

FIG. 62 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor.

FIG. 63 depicts an embodiment of a three-phase temperature limitedheater with a portion shown in cross section.

FIG. 64 depicts an embodiment of temperature limited heaters coupledtogether in a three-phase configuration.

FIG. 65 depicts an embodiment of three heaters coupled in a three-phaseconfiguration.

FIG. 66 depicts a side view representation of an embodiment of asubstantially u-shaped three-phase heater.

FIG. 67 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a formation.

FIG. 68 depicts a top view representation of the embodiment depicted inFIG. 67 with production wells.

FIG. 69 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a hexagonal pattern.

FIG. 70 depicts a top view representation of an embodiment of a hexagonfrom FIG. 69.

FIG. 71 depicts an embodiment of triads of heaters coupled to ahorizontal bus bar.

FIGS. 72 and 73 depict embodiments for coupling contacting elements ofthree legs of a heater.

FIG. 74 depicts an embodiment of a container with an initiator formelting the coupling material.

FIG. 75 depicts an embodiment of a container for coupling contactingelements with bulbs on the contacting elements.

FIG. 76 depicts an alternative embodiment of a container.

FIG. 77 depicts an alternative embodiment for coupling contactingelements of three legs of a heater.

FIG. 78 depicts a cross-sectional representation of an embodiment forcoupling contacting elements using temperature limited heating elements.

FIG. 79 depicts a cross-sectional representation of an alternativeembodiment or coupling contacting elements using temperature limitedheating elements.

FIG. 80 depicts a cross-sectional representation of another alternativeembodiment for coupling contacting elements using temperature limitedheating elements.

FIG. 81 depicts a side view representation of an alternative embodimentfor coupling contacting elements of three legs of a heater.

FIG. 82 depicts a top view representation of the alternative embodimentfor coupling contacting elements of three legs of a heater depicted inFIG. 81.

FIG. 83 depicts an embodiment of a contacting element with a brushcontactor.

FIG. 84 depicts an embodiment for coupling contacting elements withbrush contactors.

FIG. 85 depicts an embodiment of two temperature limited heaters coupledtogether in a single contacting section.

FIG. 86 depicts an embodiment of two temperature limited heaters withlegs coupled in a contacting section.

FIG. 87 depicts an embodiment of three dyads coupled to a three-phasetransformer.

FIG. 88 depicts an embodiment of groups of diads in a hexagonal pattern.

FIG. 89 depicts an embodiment of diads in a triangular pattern.

FIG. 90 depicts a cross-sectional representation of an embodiment ofsubstantially u-shaped heaters.

FIG. 91 depicts a representational top view of an embodiment of asurface pattern of heaters depicted in FIG. 90.

FIG. 92 depicts a cross-sectional representation of substantiallyu-shaped heaters in a hydrocarbon layer.

FIG. 93 depicts a side view representation of an embodiment ofsubstantially vertical heaters coupled to a substantially horizontalwellbore.

FIG. 94 depicts an embodiment of a substantially u-shaped heater thatelectrically isolates itself from the formation.

FIG. 95 depicts an embodiment of a single-ended, substantiallyhorizontal heater that electrically isolates itself from the formation.

FIG. 96 depicts an embodiment of a single-ended, substantiallyhorizontal heater that electrically isolates itself from the formationusing an insulated conductor as the center conductor.

FIGS. 97A and 97B depict an embodiment for using substantially u-shapedwellbores to time sequence heat two layers in a hydrocarbon containingformation.

FIG. 98 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a relativelythin hydrocarbon layer.

FIG. 99 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a hydrocarbonlayer that is thicker than the hydrocarbon layer depicted in FIG. 98.

FIG. 100 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a hydrocarbonlayer that is thicker than the hydrocarbon layer depicted in FIG. 99.

FIG. 101 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a hydrocarbonlayer that has a shale break.

FIG. 102 depicts a top view representation of an embodiment forpreheating using heaters for the drive process.

FIG. 103 depicts a side view representation of an embodiment forpreheating using heaters for the drive process.

FIG. 104 depicts a representation of an embodiment for producinghydrocarbons from a tar sands formation.

FIG. 105 depicts an embodiment for heating and producing from aformation with a temperature limited heater in a production wellbore.

FIG. 106 depicts an embodiment for heating and producing from aformation with a temperature limited heater and a production wellbore.

FIG. 107 depicts an embodiment of a heating/production assembly that maybe located in a wellbore for gas lifting.

FIG. 108 depicts an embodiment of a heating/production assembly that maybe located in a wellbore for gas lifting.

FIG. 109 depicts another embodiment of a heating/production assemblythat may be located in a wellbore for gas lifting.

FIG. 110 depicts an embodiment of a production conduit and a heater.

FIG. 111 depicts an embodiment for treating a formation.

FIG. 112 depicts an embodiment of a heater well with selective heating.

FIG. 113 depicts a schematic representation of an embodiment of adownhole oxidizer assembly.

FIG. 114 depicts an embodiment of a portion of an oxidizer of anoxidation system.

FIG. 115 depicts a schematic representation of an oxidizer positioned inan oxidant line.

FIG. 116 depicts a cross-sectional view of an embodiment of a heatshield.

FIG. 117 depicts a cross-sectional view of an embodiment of a heatshield.

FIG. 118 depicts a cross-sectional view of an embodiment of a heatshield.

FIG. 119 depicts a cross-sectional view of an embodiment of a heatshield.

FIG. 120 depicts a cross-sectional view of an embodiment of a heatshield.

FIG. 121 depicts a cross-sectional representation of an embodiment of acatalytic burner.

FIG. 122 depicts a cross-sectional representation of an embodiment of acatalytic burner with an igniter.

FIG. 123 depicts a schematic representation of an embodiment of aheating system with a downhole gas turbine.

FIG. 124 depicts a schematic representation of a closed loop circulationsystem for heating a portion of a formation.

FIG. 125 depicts a plan view of wellbore entries and exits from aportion of a formation to be heated using a closed loop circulationsystem.

FIG. 126 depicts a schematic representation of an embodiment of an insitu heat treatment system that uses a nuclear reactor.

FIG. 127 depicts an elevational view of an in situ heat treatment systemusing pebble bed reactors.

FIG. 128 depicts a side view representation of an embodiment of a systemfor heating the formation that can use a closed loop circulation systemand/or electrical heating.

FIG. 129 depicts a side view representation of an embodiment for an insitu staged heating and producing process for treating a tar sandsformation.

FIG. 130 depicts a top view of a rectangular checkerboard patternembodiment for the in situ staged heating and production process.

FIG. 131 depicts a top view of a ring pattern embodiment for the in situstaged heating and production process.

FIG. 132 depicts a top view of a checkerboard ring pattern embodimentfor the in situ staged heating and production process.

FIG. 133 depicts a top view an embodiment of a plurality of rectangularcheckerboard patterns in a treatment area for the in situ staged heatingand production process.

FIG. 134 depicts a schematic representation of a system for inhibitingmigration of formation fluid from a treatment area.

FIG. 135 depicts an embodiment of a windmill for generating electricityfor subsurface heaters.

FIG. 136 depicts an embodiment of a solution mining well.

FIG. 137 depicts a representation of a portion of a solution miningwell.

FIG. 138 depicts a representation of a portion of a solution miningwell.

FIG. 139 depicts an elevational view of a well pattern for solutionmining and/or an in situ heat treatment process.

FIG. 140 depicts a representation of wells of an in situ heatingtreatment process for solution mining and producing hydrocarbons from aformation.

FIG. 141 depicts an embodiment for solution mining a formation.

FIG. 142 depicts an embodiment of a formation with nahcolite layers inthe formation before solution mining nahcolite from the formation.

FIG. 143 depicts the formation of FIG. 142 after the nahcolite has beensolution mined.

FIG. 144 depicts an embodiment of two injection wells interconnected bya zone that has been solution mined to remove nahcolite from the zone.

FIG. 145 depicts an embodiment for heating a formation with dawsonite inthe formation.

FIG. 146 depicts an embodiment of treating a hydrocarbon containingformation with a combustion front.

FIG. 147 depicts a cross-sectional view of an embodiment of treating ahydrocarbon containing formation with a combustion front.

FIG. 148 depicts electrical resistance versus temperature at variousapplied electrical currents for a 446 stainless steel rod.

FIG. 149 shows resistance profiles as a function of temperature atvarious applied electrical currents for a copper rod contained in aconduit of Sumitomo HCM12A.

FIG. 150 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 151 depicts raw data for a temperature limited heater.

FIG. 152 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 153 depicts power versus temperature at various applied electricalcurrents for a temperature limited heater.

FIG. 154 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 155 depicts data of electrical resistance versus temperature for asolid 2.54 cm diameter, 1.8 m long 410 stainless steel rod at variousapplied electrical currents.

FIG. 156 depicts data of electrical resistance versus temperature for acomposite 1.9 cm, 1.8 m long alloy 42-6 rod with a copper core (the rodhas an outside diameter to copper diameter ratio of 2:1) at variousapplied electrical currents.

FIG. 157 depicts data of power output versus temperature for a composite1.9 cm, 1.8 m long alloy 42-6 rod with a copper core (the rod has anoutside diameter to copper diameter ratio of 2:1) at various appliedelectrical currents.

FIG. 158 depicts data for values of skin depth versus temperature for asolid 2.54 cm diameter, 1.8 m long 410 stainless steel rod at variousapplied AC electrical currents.

FIG. 159 depicts temperature versus time for a temperature limitedheater.

FIG. 160 depicts temperature versus log time data for a 2.5 cm solid 410stainless steel rod and a 2.5 cm solid 304 stainless steel rod.

FIG. 161 depicts experimentally measured resistance versus temperatureat several currents for a temperature limited heater with a copper core,a carbon steel ferromagnetic conductor, and a 347H stainless steelsupport member.

FIG. 162 depicts experimentally measured resistance versus temperatureat several currents for a temperature limited heater with a copper core,an iron-cobalt ferromagnetic conductor, and a 347H stainless steelsupport member.

FIG. 163 depicts experimentally measured power factor versus temperatureat two AC currents for a temperature limited heater with a copper core,a carbon steel ferromagnetic conductor, and a 347H stainless steelsupport member.

FIG. 164 depicts experimentally measured turndown ratio versus maximumpower delivered for a temperature limited heater with a copper core, acarbon steel ferromagnetic conductor, and a 347H stainless steel supportmember.

FIG. 165 depicts examples of relative magnetic permeability versusmagnetic field for both the found correlations and raw data for carbonsteel.

FIG. 166 shows the resulting plots of skin depth versus magnetic fieldfor four temperatures and 400 A current.

FIG. 167 shows a comparison between the experimental and numerical(calculated) results for currents of 300 A, 400 A, and 500 A.

FIG. 168 shows the AC resistance per foot of the heater element as afunction of skin depth at 1100° F. calculated from the theoreticalmodel.

FIG. 169 depicts the power generated per unit length in each heatercomponent versus skin depth for a temperature limited heater.

FIGS. 170A-C compare the results of theoretical calculations withexperimental data for resistance versus temperature in a temperaturelimited heater.

FIG. 171 displays temperature of the center conductor of aconductor-in-conduit heater as a function of formation depth for a Curietemperature heater with a turndown ratio of 2:1.

FIG. 172 displays heater heat flux through a formation for a turndownratio of 2:1 along with the oil shale richness profile.

FIG. 173 displays heater temperature as a function of formation depthfor a turndown ratio of 3:1.

FIG. 174 displays heater heat flux through a formation for a turndownratio of 3:1 along with the oil shale richness profile.

FIG. 175 displays heater temperature as a function of formation depthfor a turndown ratio of 4:1.

FIG. 176 depicts heater temperature versus depth for heaters used in asimulation for heating oil shale.

FIG. 177 depicts heater heat flux versus time for heaters used in asimulation for heating oil shale.

FIG. 178 depicts accumulated heat input versus time in a simulation forheating oil shale.

FIG. 179 depicts cumulative gas production and cumulative oil productionversus time found from a STARS simulation using the heaters and heaterpattern depicted in FIGS. 65 and 67.

FIG. 180 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy TC3.

FIG. 181 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy FM-4.

FIG. 182 depicts the Curie temperature and phase transformationtemperature range for several iron alloys.

FIG. 183 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt and 0.4% by weight manganese.

FIG. 184 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.01% byweight carbon.

FIG. 185 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.085% byweight carbon.

FIG. 186 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, 0.085% by weightcarbon, and 0.4% by weight titanium.

FIG. 187 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-chromiumalloys having 12.25% by weight chromium, 0.1% by weight carbon, 0.5% byweight manganese, and 0.5% by weight silicon.

FIG. 188 depicts experimental calculation of weight percentages ofphases versus weight percentages of chromium in an alloy.

FIG. 189 depicts experimental calculation of weight percentages ofphases versus weight percentages of silicon in an alloy.

FIG. 190 depicts experimental calculation of weight percentages ofphases versus weight percentages of tungsten in an alloy.

FIG. 191 depicts experimental calculation of weight percentages ofphases versus weight percentages of niobium in an alloy.

FIG. 192 depicts experimental calculation of weight percentages ofphases versus weight percentages of carbon in an alloy.

FIG. 193 depicts experimental calculation of weight percentages ofphases versus weight percentages of nitrogen in an alloy.

FIG. 194 depicts experimental calculation of weight percentages ofphases versus weight percentages of titanium in an alloy.

FIG. 195 depicts experimental calculation of weight percentages ofphases versus weight percentages of copper in an alloy.

FIG. 196 depicts experimental calculation of weight percentages ofphases versus weight percentages of manganese in an alloy.

FIG. 197 depicts experimental calculation of weight percentages ofphases versus weight percentages of nickel in an alloy.

FIG. 198 depicts experimental calculation of weight percentages ofphases versus weight percentages of molybdenum in an alloy.

FIG. 199 depicts yield strengths and ultimate tensile strengths fordifferent metals.

FIG. 200 depicts projected corrosion rates over a one-year period forseveral metals in a sulfidation atmosphere.

FIG. 201 depicts projected corrosion rates over a one-year period for410 stainless steel and 410 stainless steel containing various amountsof cobalt in a sulfidation atmosphere.

FIG. 202 depicts an example of richness of an oil shale formation(gal/ton) versus depth (ft).

FIG. 203 depicts resistance per foot (mΩ/ft) versus temperature (° F.)profile of the first heater example.

FIG. 204 depicts average temperature in the formation (° F.) versus time(days) as determined by the simulation for the first example.

FIG. 205 depicts resistance per foot (mΩ/ft) versus temperature (° F.)for the second heater example.

FIG. 206 depicts average temperature in the formation (° F.) versus time(days) as determined by the simulation for the second example.

FIG. 207 depicts net heater energy input (Btu) versus time (days) forthe second example.

FIG. 208 depicts power injection per foot (W/ft) versus time (days) forthe second example.

FIG. 209 depicts resistance per foot (mΩ/ft) versus temperature (° F.)for the third heater example.

FIG. 210 depicts average temperature in the formation (° F.) versus time(days) as determined by the simulation for the third example.

FIG. 211 depicts cumulative energy injection (Btu) versus time (days)for each of the three heater examples.

FIG. 212 depicts average temperature (° F.) versus time (days) for thethird heater example with a 30 foot spacing between heaters in theformation as determined by the simulation.

FIG. 213 depicts average temperature (° F.) versus time (days) for thefourth heater example using the heater configuration and patterndepicted in FIGS. 65 and 67 as determined by the simulation.

FIG. 214 depicts a temperature profile in the formation after 360 daysusing the STARS simulation.

FIG. 215 depicts an oil saturation profile in the formation after 360days using the STARS simulation.

FIG. 216 depicts the oil saturation profile in the formation after 1095days using the STARS simulation.

FIG. 217 depicts the oil saturation profile in the formation after 1470days using the STARS simulation.

FIG. 218 depicts the oil saturation profile in the formation after 1826days using the STARS simulation.

FIG. 219 depicts the temperature profile in the formation after 1826days using the STARS simulation.

FIG. 220 depicts oil production rate and gas production rate versustime.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and may herein be described in detail. Thedrawings may not be to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit theinvention to the particular form disclosed, but on the contrary, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the present invention as definedby the appended claims.

DETAILED DESCRIPTION

The following description generally relates to systems and methods fortreating hydrocarbons in the formations. Such formations may be treatedto yield hydrocarbon products, hydrogen, and other products.

“Alternating current (AC)” refers to a time-varying current thatreverses direction substantially sinusoidally. AC produces skin effectelectricity flow in a ferromagnetic conductor.

“API gravity” refers to API gravity at 15.5° C. (60° F.). API gravity isas determined by ASTM Method D6822.

In the context of reduced heat output heating systems, apparatus, andmethods, the term “automatically” means such systems, apparatus, andmethods function in a certain way without the use of external control(for example, external controllers such as a controller with atemperature sensor and a feedback loop, PID controller, or predictivecontroller).

“Bare metal” and “exposed metal” refer to metals of elongated membersthat do not include a layer of electrical insulation, such as mineralinsulation, that is designed to provide electrical insulation for themetal throughout an operating temperature range of the elongated member.Bare metal and exposed metal may encompass a metal that includes acorrosion inhibiter such as a naturally occurring oxidation layer, anapplied oxidation layer, and/or a film. Bare metal and exposed metalinclude metals with polymeric or other types of electrical insulationthat cannot retain electrical insulating properties at typical operatingtemperature of the elongated member. Such material may be placed on themetal and may be thermally degraded during use of the heater.

“Carbon number” refers to the number of carbon atoms in a molecule. Ahydrocarbon fluid may include various hydrocarbons with different carbonnumbers. The hydrocarbon fluid may be described by a carbon numberdistribution. Carbon numbers and/or carbon number distributions may bedetermined by true boiling point distribution and/or gas-liquidchromatography.

“Cenospheres”refers to hollow particulates that are formed in thermalprocesses at high temperatures when molten components are blown up likeballoons by the volatilization of organic components.

“Chemically stability” refers to the ability of a formation fluid to betransported without components in the formation fluid reacting to formpolymers and/or compositions that plug pipelines, valves, and/orvessels.

“Clogging” refers to impeding and/or inhibiting flow of one or morecompositions through a process vessel or a conduit.

“Column X element” or “Column X elements” refer to one or more elementsof Column X of the Periodic Table, and/or one or more compounds of oneor more elements of Column X of the Periodic Table, in which Xcorresponds to a column number (for example, 13-18) of the PeriodicTable. For example, “Column 15 elements” refer to elements from Column15 of the Periodic Table and/or compounds of one or more elements fromColumn 15 of the Periodic Table.

“Column X metal” or “Column X metals” refer to one or more metals ofColumn X of the Periodic Table and/or one or more compounds of one ormore metals of Column X of the Periodic Table, in which X corresponds toa column number (for example, 1-12) of the Periodic Table. For example,“Column 6 metals” refer to metals from Column 6 of the Periodic Tableand/or compounds of one or more metals from Column 6 of the PeriodicTable.

“Condensable hydrocarbons” are hydrocarbons that condense at 25° C. andone atmosphere absolute pressure. Condensable hydrocarbons may include amixture of hydrocarbons having carbon numbers greater than 4.“Non-condensable hydrocarbons” are hydrocarbons that do not condense at25° C. and one atmosphere absolute pressure. Non-condensablehydrocarbons may include hydrocarbons having carbon numbers less than 5.

“Coring” is a process that generally includes drilling a hole into aformation and removing a substantially solid mass of the formation fromthe hole.

“Cracking” refers to a process involving decomposition and molecularrecombination of organic compounds to produce a greater number ofmolecules than were initially present. In cracking, a series ofreactions take place accompanied by a transfer of hydrogen atoms betweenmolecules. For example, naphtha may undergo a thermal cracking reactionto form ethene and H₂.

“Curie temperature” is the temperature above which a ferromagneticmaterial loses all of its ferromagnetic properties. In addition tolosing all of its ferromagnetic properties above the Curie temperature,the ferromagnetic material begins to lose its ferromagnetic propertieswhen an increasing electrical current is passed through theferromagnetic material.

“Cycle oil” refers to a mixture of light cycle oil and heavy cycle oil.“Light cycle oil” refers to hydrocarbons having a boiling rangedistribution between 430° F. (221° C.) and 650° F. (343° C.) that are prcatalytic cracking system. Light cycle oil content is determined by ASTMMethod D5307. “Heavy cycle oil” refers to hydrocarbons having a boilingrange distribution between 650° F. (343° C.) and 800° F. (427° C.) thatare produced from a fluidized catalytic cracking system. Heavy cycle oilcontent is determined by ASTM Method D5307.

“Diad” refers to a group of two items (for example, heaters, wellbores,or other objects) coupled together.

“Diesel” refers to hydrocarbons with a boiling range distributionbetween 260° C. and 343° C. (500-650° F.) at 0.101 MPa. Diesel contentis determined by ASTM Method D2887.

“Enriched air” refers to air having a larger mole fraction of oxygenthan air in the atmosphere. Air is typically enriched to increasecombustion-supporting ability of the air.

“Fluid pressure” is a pressure generated by a fluid in a formation.“Lithostatic pressure” (sometimes referred to as “lithostatic stress”)is a pressure in a formation equal to a weight per unit area of anoverlying rock mass. “Hydrostatic pressure” is a pressure in a formationexerted by a column of water.

A “formation” includes one or more hydrocarbon containing layers, one ormore non-hydrocarbon layers, an overburden, and/or an underburden.“Hydrocarbon layers” refer to layers in the formation that containhydrocarbons. The hydrocarbon layers may contain non-hydrocarbonmaterial and hydrocarbon material. The “overburden” and/or the“underburden” include one or more different types of impermeablematerials. For example, the overburden and/or underburden may includerock, shale, mudstone, or wet/tight carbonate. In some embodiments of insitu heat treatment processes, the overburden and/or the underburden mayinclude a hydrocarbon containing layer or hydrocarbon containing layersthat are relatively impermeable and are not subjected to temperaturesduring in situ heat treatment processing that result in significantcharacteristic changes of the hydrocarbon containing layers of theoverburden and/or the underburden. For example, the underburden maycontain shale or mudstone, but the underburden is not allowed to heat topyrolysis temperatures during the in situ heat treatment process. Insome cases, the overburden and/or the underburden may be somewhatpermeable.

“Formation fluids” refer to fluids present in a formation and mayinclude pyrolyzation fluid, synthesis gas, mobilized hydrocarbon, andwater (steam). Formation fluids may include hydrocarbon fluids as wellas non-hydrocarbon fluids. The term “mobilized fluid” refers to fluidsin a hydrocarbon containing formation that are able to flow as a resultof thermal treatment of the formation. “Produced fluids” refer to fluidsremoved from the formation.

“Gasoline hydrocarbons” refer to hydrocarbons having a boiling pointrange from 32° C. (90° F.) to about 204° C. (400° F.). Gasolinehydrocarbons include, but are not limited to, straight run gasoline,naphtha, fluidized or thermally catalytically cracked gasoline, VBgasoline, and coker gasoline. Gasoline hydrocarbons content isdetermined by ASTM Method D2887.

A “heat source” is any system for providing heat to at least a portionof a formation substantially by conductive and/or radiative heattransfer. For example, a heat source may include electric heaters suchas an insulated conductor, an elongated member, and/or a conductordisposed in a conduit. A heat source may also include systems thatgenerate heat by burning a fuel external to or in a formation. Thesystems may be surface burners, downhole gas burners, flamelessdistributed combustors, and natural distributed combustors. In someembodiments, heat provided to or generated in one or more heat sourcesmay be supplied by other sources of energy. The other sources of energymay directly heat a formation, or the energy may be applied to atransfer medium that directly or indirectly heats the formation. It isto be understood that one or more heat sources that are applying heat toa formation may use different sources of energy. Thus, for example, fora given formation some heat sources may supply heat from electricresistance heaters, some heat sources may provide heat from combustion,and some heat sources may provide heat from one or more other energysources (for example, chemical reactions, solar energy, wind energy,biomass, or other sources of renewable energy). A chemical reaction mayinclude an exothermic reaction (for example, an oxidation reaction). Aheat source may also include a heater that provides heat to a zoneproximate and/or surrounding a heating location such as a heater well.

A “heater” is any system or heat source for generating heat in a well ora near wellbore region. Heaters may be, but are not limited to, electricheaters, burners, combustors that react with material in or producedfrom a formation, and/or combinations thereof.

“Heavy hydrocarbons” are viscous hydrocarbon fluids. Heavy hydrocarbonsmay include highly viscous hydrocarbon fluids such as heavy oil, tar,and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, aswell as smaller concentrations of sulfur, oxygen, and nitrogen.Additional elements may also be present in heavy hydrocarbons in traceamounts. Heavy hydrocarbons may be classified by API gravity. Heavyhydrocarbons generally have an API gravity below about 20°. Heavy oil,for example, generally has an API gravity of about 10-20°, whereas targenerally has an API gravity below about 10°. The viscosity of heavyhydrocarbons is generally greater than about 100 centipoise at 15° C.Heavy hydrocarbons may include aromatics or other complex ringhydrocarbons.

Heavy hydrocarbons may be found in a relatively permeable formation. Therelatively permeable formation may include heavy hydrocarbons entrainedin, for example, sand or carbonate. “Relatively permeable” is defined,with respect to formations or portions thereof, as an averagepermeability of 10 millidarcy or more (for example, 10 or 100millidarcy). “Relatively low permeability” is defined, with respect toformations or portions thereof, as an average permeability of less thanabout 10 millidarcy. One darcy is equal to about 0.99 squaremicrometers. An impermeable layer generally has a permeability of lessthan about 0.1 millidarcy.

Certain types of formations that include heavy hydrocarbons may also be,but are not limited to, natural mineral waxes, or natural asphaltites.“Natural mineral waxes” typically occur in substantially tubular veinsthat may be several meters wide, several kilometers long, and hundredsof meters deep. “Natural asphaltites” include solid hydrocarbons of anaromatic composition and typically occur in large veins. In siturecovery of hydrocarbons from formations such as natural mineral waxesand natural asphaltites may include melting to form liquid hydrocarbonsand/or solution mining of hydrocarbons from the formations.

“Hydrocarbons” are generally defined as molecules formed primarily bycarbon and hydrogen atoms. Hydrocarbons may also include other elementssuch as, but not limited to, halogens, metallic elements, nitrogen,oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to,kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, andasphaltites. Hydrocarbons may be located in or adjacent to mineralmatrices in the earth. Matrices may include, but are not limited to,sedimentary rock, sands, silicilytes, carbonates, diatomites, and otherporous media. “Hydrocarbon fluids” are fluids that include hydrocarbons.Hydrocarbon fluids may include, entrain, or be entrained innon-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide,carbon dioxide, hydrogen sulfide, water, and ammonia.

An “in situ conversion process” refers to a process of heating ahydrocarbon containing formation from heat sources to raise thetemperature of at least a portion of the formation above a pyrolysistemperature so that pyrolyzation fluid is produced in the formation.

An “in situ heat treatment process” refers to a process of heating ahydrocarbon containing formation with heat sources to raise thetemperature of at least a portion of the formation above a temperaturethat results in mobilized fluid, visbreaking, and/or pyrolysis ofhydrocarbon containing material so that mobilized fluids, visbrokenfluids, and/or pyrolyzation fluids are produced in the formation.

“Insulated conductor” refers to any elongated material that is able toconduct electricity and that is covered, in whole or in part, by anelectrically insulating material.

“Karst” is a subsurface shaped by the dissolution of a soluble layer orlayers of bedrock, usually carbonate rock such as limestone or dolomite.The dissolution may be caused by meteoric or acidic water. The Grosmontformation in Alberta, Canada is an example of a karst (or “karsted”)carbonate formation.

“Kerogen” is a solid, insoluble hydrocarbon that has been converted bynatural degradation and that principally contains carbon, hydrogen,nitrogen, oxygen, and sulfur. Coal and oil shale are typical examples ofmaterials that contain kerogen. “Bitumen” is a non-crystalline solid orviscous hydrocarbon material that is substantially soluble in carbondisulfide. “Oil” is a fluid containing a mixture of condensablehydrocarbons.

“Kerosene” refers to hydrocarbons with a boiling range distributionbetween 204° C. and 260° C. at 0.101 MPa. Kerosene content is determinedby ASTM Method D2887.

“Modulated direct current (DC)” refers to any substantiallynon-sinusoidal time-varying current that produces skin effectelectricity flow in a ferromagnetic conductor.

“Naphtha” refers to hydrocarbon components with a boiling rangedistribution between 38° C. and 200° C. at 0.101 MPa. Naphtha content isdetermined by American Standard Testing and Materials (ASTM) MethodD5307.

“Nitride” refers to a compound of nitrogen and one or more otherelements of the Periodic Table. Nitrides include, but are not limitedto, silicon nitride, boron nitride, or alumina nitride.

“Octane Number” refers to a calculated numerical representation of theantiknock properties of a motor fuel compared to a standard referencefuel. A calculated octane number is determined by ASTM Method D6730.

“Olefins” are molecules that include unsaturated hydrocarbons having oneor more non-aromatic carbon-carbon double bonds.

“Orifices” refer to openings, such as openings in conduits, having awide variety of sizes and cross-sectional shapes including, but notlimited to, circles, ovals, squares, rectangles, triangles, slits, orother regular or irregular shapes.

“Periodic Table” refers to the Periodic Table as specified by theInternational Union of Pure and Applied Chemistry (IUPAC), November2003. In the scope of this application, weight of a metal from thePeriodic Table, weight of a compound of a metal from the Periodic Table,weight of an element from the Periodic Table, or weight of a compound ofan element from the Periodic Table is calculated as the weight of metalor the weight of element. For example, if 0.1 grams of MoO₃ is used pergram of catalyst, the calculated weight of the molybdenum metal in thecatalyst is 0.067 grams per gram of catalyst.

“Physical stability”refers the ability of a formation fluid to notexhibit phase separation or flocculation during transportation of thefluid. Physical stability is determined by ASTM Method D7060.

“Pyrolysis” is the breaking of chemical bonds due to the application ofheat. For example, pyrolysis may include transforming a compound intoone or more other substances by heat alone. Heat may be transferred to asection of the formation to cause pyrolysis.

“Pyrolyzation fluids” or “pyrolysis products” refers to fluid producedsubstantially during pyrolysis of hydrocarbons. Fluid produced bypyrolysis reactions may mix with other fluids in a formation. Themixture would be considered pyrolyzation fluid or pyrolyzation product.As used herein, “pyrolysis zone” refers to a volume of a formation (forexample, a relatively permeable formation such as a tar sands formation)that is reacted or reacting to form a pyrolyzation fluid.

“Rich layers” in a hydrocarbon containing formation are relatively thinlayers (typically about 0.2 m to about 0.5 m thick). Rich layersgenerally have a richness of about 0.150 L/kg or greater. Some richlayers have a richness of about 0.170 L/kg or greater, of about 0.190L/kg or greater, or of about 0.210 L/kg or greater. Lean layers of theformation have a richness of about 0.100 L/kg or less and are generallythicker than rich layers. The richness and locations of layers aredetermined, for example, by coring and subsequent Fischer assay of thecore, density or neutron logging, or other logging methods. Rich layersmay have a lower initial thermal conductivity than other layers of theformation. Typically, rich layers have a thermal conductivity 1.5 timesto 3 times lower than the thermal conductivity of lean layers. Inaddition, rich layers have a higher thermal expansion coefficient thanlean layers of the formation.

“Smart well technology” or “smart wellbore” refers to wells thatincorporate downhole measurement and/or control. For injection wells,smart well technology may allow for controlled injection of fluid intothe formation in desired zones. For production wells, smart welltechnology may allow for controlled production of formation fluid fromselected zones. Some wells may include smart well technology that allowsfor formation fluid production from selected zones and simultaneous orstaggered solution injection into other zones. Smart well technology mayinclude fiber optic systems and control valves in the wellbore. A smartwellbore used for an in situ heat treatment process may be WestbayMultilevel Well System MP55 available from Westbay Instruments Inc.(Burnaby, British Columbia, Canada).

“Subsidence” is a downward movement of a portion of a formation relativeto an initial elevation of the surface.

“Superposition of heat” refers to providing heat from two or more heatsources to a selected section of a formation such that the temperatureof the formation at least at one location between the heat sources isinfluenced by the heat sources.

“Synthesis gas” is a mixture including hydrogen and carbon monoxide.Additional components of synthesis gas may include water, carbondioxide, nitrogen, methane, and other gases. Synthesis gas may begenerated by a variety of processes and feedstocks. Synthesis gas may beused for synthesizing a wide range of compounds.

“Tar” is a viscous hydrocarbon that generally has a viscosity greaterthan about 10,000 centipoise at 15° C. The specific gravity of targenerally is greater than 1.000. Tar may have an API gravity less than10°.

A “tar sands formation” is a formation in which hydrocarbons arepredominantly present in the form of heavy hydrocarbons and/or tarentrained in a mineral grain framework or other host lithology (forexample, sand or carbonate). Examples of tar sands formations includeformations such as the Athabasca formation, the Grosmont formation, andthe Peace River formation, all three in Alberta, Canada; and the Fajaformation in the Orinoco belt in Venezuela.

“Temperature limited heater” generally refers to a heater that regulatesheat output (for example, reduces heat output) above a specifiedtemperature without the use of external controls such as temperaturecontrollers, power regulators, rectifiers, or other devices. Temperaturelimited heaters may be AC (alternating current) or modulated (forexample, “chopped”) DC (direct current) powered electrical resistanceheaters.

“Thermally conductive fluid” includes fluid that has a higher thermalconductivity than air at standard temperature and pressure (STP) (0° C.and 101.325 kPa).

“Thermal conductivity” is a property of a material that describes therate at which heat flows, in steady state, between two surfaces of thematerial for a given temperature difference between the two surfaces.

“Thermal fracture” refers to fractures created in a formation caused byexpansion or contraction of a formation and/or fluids in the formation,which is in turn caused by increasing/decreasing the temperature of theformation and/or fluids in the formation, and/or byincreasing/decreasing a pressure of fluids in the formation due toheating.

“Thickness” of a layer refers to the thickness of a cross section of thelayer, wherein the cross section is normal to a face of the layer.

“Time-varying current” refers to electrical current that produces skineffect electricity flow in a ferromagnetic conductor and has a magnitudethat varies with time. Time-varying current includes both alternatingcurrent (AC) and modulated direct current (DC).

“Triad” refers to a group of three items (for example, heaters,wellbores, or other objects) coupled together.

“Turndown ratio” for the temperature limited heater is the ratio of thehighest AC or modulated DC resistance below the Curie temperature to thelowest resistance above the Curie temperature for a given current.

A “u-shaped wellbore” refers to a wellbore that extends from a firstopening in the formation, through at least a portion of the formation,and out through a second opening in the formation. In this context, thewellbore may be only roughly in the shape of a “v” or “u”, with theunderstanding that the “legs” of the “u” do not need to be parallel toeach other, or perpendicular to the “bottom” of the “u” for the wellboreto be considered “u-shaped”.

“Upgrade” refers to increasing the quality of hydrocarbons. For example,upgrading heavy hydrocarbons may result in an increase in the APIgravity of the heavy hydrocarbons.

“Visbreaking” refers to the untangling of molecules in fluid during heattreatment and/or to the breaking of large molecules into smallermolecules during heat treatment, which results in a reduction of theviscosity of the fluid.

“VGO” or “vacuum gas oil” refers to hydrocarbons with a boiling rangedistribution between 343° C. and 538° C. at 0.101 MPa. VGO content isdetermined by ASTM Method D5307.

A “vug” is a cavity, void or large pore in a rock that is commonly linedwith mineral precipitates.

“Wax” refers to a low melting organic mixture, or a compound of highmolecular weight that is a solid at lower temperatures and a liquid athigher temperatures, and when in solid form can form a barrier to water.Examples of waxes include animal waxes, vegetable waxes, mineral waxes,petroleum waxes, and synthetic waxes.

The term “wellbore” refers to a hole in a formation made by drilling orinsertion of a conduit into the formation. A wellbore may have asubstantially circular cross section, or another cross-sectional shape.As used herein, the terms “well” and “opening,” when referring to anopening in the formation may be used interchangeably with the term“wellbore.”

Hydrocarbons in formations may be treated in various ways to producemany different products. In certain embodiments, hydrocarbons informations are treated in stages. FIG. 1 depicts an illustration ofstages of heating the hydrocarbon containing formation. FIG. 1 alsodepicts an example of yield (“Y”) in barrels of oil equivalent per ton(y axis) of formation fluids from the formation versus temperature (“T”)of the heated formation in degrees Celsius (x axis).

Desorption of methane and vaporization of water occurs during stage 1heating. Heating of the formation through stage 1 may be performed asquickly as possible. For example, when the hydrocarbon containingformation is initially heated, hydrocarbons in the formation desorbadsorbed methane. The desorbed methane may be produced from theformation. If the hydrocarbon containing formation is heated further,water in the hydrocarbon containing formation is vaporized. Water mayoccupy, in some hydrocarbon containing formations, between 10% and 50%of the pore volume in the formation. In other formations, water occupieslarger or smaller portions of the pore volume. Water typically isvaporized in a formation between 160° C. and 285° C. at pressures of 600kPa absolute to 7000 kPa absolute. In some embodiments, the vaporizedwater produces wettability changes in the formation and/or increasedformation pressure. The wettability changes and/or increased pressuremay affect pyrolysis reactions or other reactions in the formation. Incertain embodiments, the vaporized water is produced from the formation.In other embodiments, the vaporized water is used for steam extractionand/or distillation in the formation or outside the formation. Removingthe water from and increasing the pore volume in the formation increasesthe storage space for hydrocarbons in the pore volume.

In certain embodiments, after stage 1 heating, the formation is heatedfurther, such that a temperature in the formation reaches (at least) aninitial pyrolyzation temperature (such as a temperature at the lower endof the temperature range shown as stage 2). Hydrocarbons in theformation may be pyrolyzed throughout stage 2. A pyrolysis temperaturerange varies depending on the types of hydrocarbons in the formation.The pyrolysis temperature range may include temperatures between 250° C.and 900° C. The pyrolysis temperature range for producing desiredproducts may extend through only a portion of the total pyrolysistemperature range. In some embodiments, the pyrolysis temperature rangefor producing desired products may include temperatures between 250° C.and 400° C. or temperatures between 270° C. and 350° C. If a temperatureof hydrocarbons in the formation is slowly raised through thetemperature range from 250° C. to 400° C., production of pyrolysisproducts may be substantially complete when the temperature approaches400° C. Average temperature of the hydrocarbons may be raised at a rateof less than 5° C. per day, less than 2° C. per day, less than 1° C. perday, or less than 0.5° C. per day through the pyrolysis temperaturerange for producing desired products. Heating the hydrocarbon containingformation with a plurality of heat sources may establish thermalgradients around the heat sources that slowly raise the temperature ofhydrocarbons in the formation through the pyrolysis temperature range.

The rate of temperature increase through the pyrolysis temperature rangefor desired products may affect the quality and quantity of theformation fluids produced from the hydrocarbon containing formation.Raising the temperature slowly through the pyrolysis temperature rangefor desired products may inhibit mobilization of large chain moleculesin the formation. Raising the temperature slowly through the pyrolysistemperature range for desired products may limit reactions betweenmobilized hydrocarbons that produce undesired products. Slowly raisingthe temperature of the formation through the pyrolysis temperature rangefor desired products may allow for the production of high quality, highAPI gravity hydrocarbons from the formation. Slowly raising thetemperature of the formation through the pyrolysis temperature range fordesired products may allow for the removal of a large amount of thehydrocarbons present in the formation as hydrocarbon product.

In some in situ heat treatment embodiments, a portion of the formationis heated to a desired temperature instead of slowly heating thetemperature through a temperature range. In some embodiments, thedesired temperature is 300° C., 325° C., or 350° C. Other temperaturesmay be selected as the desired temperature. Superposition of heat fromheat sources allows the desired temperature to be relatively quickly andefficiently established in the formation. Energy input into theformation from the heat sources may be adjusted to maintain thetemperature in the formation substantially at the desired temperature.The heated portion of the formation is maintained substantially at thedesired temperature until pyrolysis declines such that production ofdesired formation fluids from the formation becomes uneconomical. Partsof the formation that are subjected to pyrolysis may include regionsbrought into a pyrolysis temperature range by heat transfer from onlyone heat source.

In certain embodiments, formation fluids including pyrolyzation fluidsare produced from the formation. As the temperature of the formationincreases, the amount of condensable hydrocarbons in the producedformation fluid may decrease. At high temperatures, the formation mayproduce mostly methane and/or hydrogen. If the hydrocarbon containingformation is heated throughout an entire pyrolysis range, the formationmay produce only small amounts of hydrogen towards an upper limit of thepyrolysis range. After all of the available hydrogen is depleted, aminimal amount of fluid production from the formation will typicallyoccur.

After pyrolysis of hydrocarbons, a large amount of carbon and somehydrogen may still be present in the formation. A significant portion ofcarbon remaining in the formation can be produced from the formation inthe form of synthesis gas. Synthesis gas generation may take placeduring stage 3 heating depicted in FIG. 1. Stage 3 may include heating ahydrocarbon containing formation to a temperature sufficient to allowsynthesis gas generation. For example, synthesis gas may be produced ina temperature range from about 400° C. to about 1200° C., about 500° C.to about 1100° C., or about 550° C. to about 1000° C. The temperature ofthe heated portion of the formation when the synthesis gas generatingfluid is introduced to the formation determines the composition ofsynthesis gas produced in the formation. The generated synthesis gas maybe removed from the formation through a production well or productionwells.

Total energy content of fluids produced from the hydrocarbon containingformation may stay relatively constant throughout pyrolysis andsynthesis gas generation. During pyrolysis at relatively low formationtemperatures, a significant portion of the produced fluid may becondensable hydrocarbons that have a high energy content. At higherpyrolysis temperatures, however, less of the formation fluid may includecondensable hydrocarbons. More non-condensable formation fluids may beproduced from the formation. Energy content per unit volume of theproduced fluid may decline slightly during generation of predominantlynon-condensable formation fluids. During synthesis gas generation,energy content per unit volume of produced synthesis gas declinessignificantly compared to energy content of pyrolyzation fluid. Thevolume of the produced synthesis gas, however, will in many instancesincrease substantially, thereby compensating for the decreased energycontent.

FIG. 2 depicts a schematic view of an embodiment of a portion of the insitu heat treatment system for treating the hydrocarbon containingformation. The in situ heat treatment system may include barrier wells200. Barrier wells are used to form a barrier around a treatment area.The barrier inhibits fluid flow into and/or out of the treatment area.Barrier wells include, but are not limited to, dewatering wells, vacuumwells, capture wells, injection wells, grout wells, freeze wells, orcombinations thereof. In some embodiments, barrier wells 200 aredewatering wells. Dewatering wells may remove liquid water and/orinhibit liquid water from entering a portion of the formation to beheated, or to the formation being heated. In the embodiment depicted inFIG. 2, the barrier wells 200 are shown extending only along one side ofheat sources 202, but the barrier wells typically encircle all heatsources 202 used, or to be used, to heat a treatment area of theformation.

Heat sources 202 are placed in at least a portion of the formation. Heatsources 202 may include heaters such as insulated conductors,conductor-in-conduit heaters, surface burners, flameless distributedcombustors, and/or natural distributed combustors. Heat sources 202 mayalso include other types of heaters. Heat sources 202 provide heat to atleast a portion of the formation to heat hydrocarbons in the formation.Energy may be supplied to heat sources 202 through supply lines 204.Supply lines 204 may be structurally different depending on the type ofheat source or heat sources used to heat the formation. Supply lines 204for heat sources may transmit electricity for electric heaters, maytransport fuel for combustors, or may transport heat exchange fluid thatis circulated in the formation. In some embodiments, electricity for anin situ heat treatment process may be provided by a nuclear power plantor nuclear power plants. The use of nuclear power may allow forreduction or elimination of carbon dioxide emissions from the in situheat treatment process.

When the formation is heated, the heat input into the formation maycause expansion of the formation and geomechanical motion. The heatsources may be turned on before, at the same time, or during adewatering process. Computer simulations may model formation response toheating. The computer simulations may be used to develop a pattern andtime sequence for activating heat sources in the formation so thatgeomechanical motion of the formation does not adversely affect thefunctionality of heat sources, production wells, and other equipment inthe formation.

Heating the formation may cause an increase in permeability and/orporosity of the formation. Increases in permeability and/or porosity mayresult from a reduction of mass in the formation due to vaporization andremoval of water, removal of hydrocarbons, and/or creation of fractures.Fluid may flow more easily in the heated portion of the formationbecause of the increased permeability and/or porosity of the formation.Fluid in the heated portion of the formation may move a considerabledistance through the formation because of the increased permeabilityand/or porosity. The considerable distance may be over 1000 m dependingon various factors, such as permeability of the formation, properties ofthe fluid, temperature of the formation, and pressure gradient allowingmovement of the fluid. The ability of fluid to travel considerabledistance in the formation allows production wells 206 to be spacedrelatively far apart in the formation.

Production wells 206 are used to remove formation fluid from theformation. In some embodiments, production well 206 includes a heatsource. The heat source in the production well may heat one or moreportions of the formation at or near the production well. In some insitu heat treatment process embodiments, the amount of heat supplied tothe formation from the production well per meter of the production wellis less than the amount of heat applied to the formation from a heatsource that heats the formation per meter of the heat source. Heatapplied to the formation from the production well may increase formationpermeability adjacent to the production well by vaporizing and removingliquid phase fluid adjacent to the production well and/or by increasingthe permeability of the formation adjacent to the production well byformation of macro and/or micro fractures.

More than one heat source may be positioned in the production well. Aheat source in a lower portion of the production well may be turned offwhen superposition of heat from adjacent heat sources heats theformation sufficiently to counteract benefits provided by heating theformation with the production well. In some embodiments, the heat sourcein an upper portion of the production well may remain on after the heatsource in the lower portion of the production well is deactivated. Theheat source in the upper portion of the well may inhibit condensationand reflux of formation fluid.

In some embodiments, the heat source in production well 206 allows forvapor phase removal of formation fluids from the formation. Providingheating at or through the production well may: (1) inhibit condensationand/or refluxing of production fluid when such production fluid ismoving in the production well proximate the overburden, (2) increaseheat input into the formation, (3) increase production rate from theproduction well as compared to a production well without a heat source,(4) inhibit condensation of high carbon number compounds (C₆ and above)in the production well, and/or (5) increase formation permeability at orproximate the production well.

Subsurface pressure in the formation may correspond to the fluidpressure generated in the formation. As temperatures in the heatedportion of the formation increase, the pressure in the heated portionmay increase as a result of increased fluid generation and vaporizationof water. Controlling rate of fluid removal from the formation may allowfor control of pressure in the formation. Pressure in the formation maybe determined at a number of different locations, such as near or atproduction wells, near or at heat sources, or at monitor wells.

In some hydrocarbon containing formations, production of hydrocarbonsfrom the formation is inhibited until at least some hydrocarbons in theformation have been pyrolyzed. Formation fluid may be produced from theformation when the formation fluid is of a selected quality. In someembodiments, the selected quality includes an API gravity of at leastabout 20°, 30°, or 40°. Inhibiting production until at least somehydrocarbons are pyrolyzed may increas conversion of heavy hydrocarbonsto light hydrocarbons. Inhibiting initial production may minimize theproduction of heavy hydrocarbons from the formation. Production ofsubstantial amounts of heavy hydrocarbons may require expensiveequipment and/or reduce the life of production equipment.

In some hydrocarbon containing formations, hydrocarbons in the formationmay be heated to pyrolysis temperatures before substantial permeabilityhas been generated in the heated portion of the formation. An initiallack of permeability may inhibit the transport of generated fluids toproduction wells 206. During initial heating, fluid pressure in theformation may increase proximate heat sources 202. The increased fluidpressure may be released, monitored, altered, and/or controlled throughone or more heat sources 202. For example, selected heat sources 202 orseparate pressure relief wells may include pressure relief valves thatallow for removal of some fluid from the formation.

In some embodiments, pressure generated by expansion of pyrolysis fluidsor other fluids generated in the formation may be allowed to increasealthough an open path to production wells 206 or any other pressure sinkmay not yet exist in the formation. The fluid pressure may be allowed toincrease towards a lithostatic pressure. Fractures in the hydrocarboncontaining formation may form when the fluid approaches the lithostaticpressure. For example, fractures may form from heat sources 202 toproduction wells 206 in the heated portion of the formation. Thegeneration of fractures in the heated portion may relieve some of thepressure in the portion. Pressure in the formation may have to bemaintained below a selected pressure to inhibit unwanted production,fracturing of the overburden or underburden, and/or coking ofhydrocarbons in the formation.

After pyrolysis temperatures are reached and production from theformation is allowed, pressure in the formation may be varied to alterand/or control a composition of formation fluid produced, to control apercentage of condensable fluid as compared to non-condensable fluid inthe formation fluid, and/or to control an API gravity of formation fluidbeing produced. For example, decreasing pressure may result inproduction of a larger condensable fluid component. The condensablefluid component may contain a larger percentage of olefins.

In some in situ heat treatment process embodiments, pressure in theformation may be maintained high enough to promote production offormation fluid with an API gravity of greater than 20°. Maintainingincreased pressure in the formation may inhibit formation subsidenceduring in situ heat treatment. Maintaining increased pressure mayfacilitate vapor phase production of fluids from the formation. Vaporphase production may allow for a reduction in size of collectionconduits used to transport fluids produced from the formation.Maintaining increased pressure may reduce or eliminate the need tocompress formation fluids at the surface to transport the fluids incollection conduits to treatment facilities.

Maintaining increased pressure in a heated portion of the formation maysurprisingly allow for production of large quantities of hydrocarbons ofincreased quality and of relatively low molecular weight. Pressure maybe maintained so that formation fluid produced has a minimal amount ofcompounds above a selected carbon number. The selected carbon number maybe at most 25, at most 20, at most 12, or at most 8. Some high carbonnumber compounds may be entrained in vapor in the formation and may beremoved from the formation with the vapor. Maintaining increasedpressure in the formation may inhibit entrainment of high carbon numbercompounds and/or multi-ring hydrocarbon compounds in the vapor. Highcarbon number compounds and/or multi-ring hydrocarbon compounds mayremain in a liquid phase in the formation for significant time periods.The significant time periods may provide sufficient time for thecompounds to pyrolyze to form lower carbon number compounds.

Generation of relatively low molecular weight hydrocarbons is believedto be due, in part, to autogenous generation and reaction of hydrogen ina portion of the hydrocarbon containing formation. For example,maintaining an increased pressure may force hydrogen generated duringpyrolysis into the liquid phase within the formation. Heating theportion to a temperature in a pyrolysis temperature range may pyrolyzehydrocarbons in the formation to generate liquid phase pyrolyzationfluids. The generated liquid phase pyrolyzation fluids components mayinclude double bonds and/or radicals. Hydrogen (H₂) in the liquid phasemay reduce double bonds of the generated pyrolyzation fluids, therebyreducing a potential for polymerization or formation of long chaincompounds from the generated pyrolyzation fluids. In addition, H₂ mayalso neutralize radicals in the generated pyrolyzation fluids.Therefore, H₂ in the liquid phase may inhibit the generated pyrolyzationfluids from reacting with each other and/or with other compounds in theformation.

Formation fluid produced from production wells 206 may be transportedthrough collection piping 208 to treatment facilities 210. Formationfluids may also be produced from heat sources 202. For example, fluidmay be produced from heat sources 202 to control pressure in theformation adjacent to the heat sources. Fluid produced from heat sources202 may be transported through tubing or piping to collection piping 208or the produced fluid may be transported through tubing or pipingdirectly to treatment facilities 210. Treatment facilities 210 mayinclude separation units, reaction units, upgrading units, fuel cells,turbines, storage vessels, and/or other systems and units for processingproduced formation fluids. The treatment facilities may formtransportation fuel from at least a portion of the hydrocarbons producedfrom the formation. In some embodiments, the transportation fuel may bejet fuel, such as JP-8.

Formation fluid may be hot when produced from the formation through theproduction wells. Hot formation fluid may be produced during solutionmining processes and/or during in situ heat treatment processes. In someembodiments, electricity may be generated using the heat of the fluidproduced from the formation. Also, heat recovered from the formationafter the in situ process may be used to generate electricity. Thegenerated electricity may be used to supply power to the in situ heattreatment process. For example, the electricity may be used to powerheaters, or to power a refrigeration system for forming or maintaining alow temperature barrier. Electricity may be generated using a Kalinacycle or a modified Kalina cycle.

FIG. 3 depicts a schematic representation of a Kalina cycle that usesrelatively high pressure aqua ammonia as the working fluid. Hot producedfluid from the formation may pass through line 212 to heat exchanger214. The produced fluid may have a temperature greater than about 100°C. Line 216 from heat exchanger 214 may direct the produced fluid to aseparator or other treatment unit. In some embodiments, the producedfluid is a mineral containing fluid produced during solution mining. Insome embodiments, the produced fluid includes hydrocarbons producedusing an in situ heat treatment process or using an in situ mobilizationprocess. Heat from the produced fluid is used to evaporate aqua ammoniain heat exchanger 214.

Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger 214and heat exchanger 222. Aqua ammonia from heat exchangers 214, 222passes to separator 224. Separator 224 forms a rich ammonia gas streamand a lean ammonia gas stream. The rich ammonia gas stream is sent toturbine 226 to generate electricity.

The lean ammonia gas stream from separator 224 passes through heatexchanger 222. The lean gas stream leaving heat exchanger 222 iscombined with the rich ammonia gas stream leaving turbine 226. Thecombination stream is passed through heat exchanger 228 and returned totank 218. Heat exchanger 228 may be water cooled. Heater water from heatexchanger 228 may be sent to a surface water reservoir through line 230.

FIG. 4 depicts a schematic representation of a modified Kalina cyclethat uses lower pressure aqua ammonia as the working fluid. Hot producedfluid from the formation may pass through line 212 to heat exchanger214. The produced fluid may have a temperature greater than about 100°C. Second heat exchanger 232 may further reduce the temperature of theproduced fluid from the formation before the fluid is sent through line216 to a separator or other treatment unit. Second heat exchanger may bewater cooled.

Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger234. The temperature of the aqua ammonia from tank 218 is raised in heatexchanger 234 by heat transfer with a combined aqua ammonia stream fromturbine 226 and separator 224. The aqua ammonia stream from heatexchanger 234 passes to heat exchanger 236. The temperature of thestream is raised again by transfer of heat with a lean ammonia streamthat exits separator 224. The stream then passes to heat exchanger 214.Heat from the produced fluid is used to evaporate aqua ammonia in heatexchanger 214. The aqua ammonia passes to separator 224.

Separator 224 forms a rich ammonia gas stream and a lean ammonia gasstream. The rich ammonia gas stream is sent to turbine 226 to generateelectricity. The lean ammonia gas stream passes through heat exchanger236. After heat exchanger 236, the lean ammonia gas stream is combinedwith the rich ammonia gas stream leaving turbine 226. The combined gasstream is passed through heat exchanger 234 to cooler 238. After cooler238, the stream returns to tank 218.

In some embodiments, formation fluid produced from the in situ heattreatment process is sent to a separator to split the stream into one ormore in situ heat treatment process liquid streams and/or one or more insitu heat treatment process gas streams. The liquid streams and the gasstreams may be further treated to yield desired products.

In some embodiments, in situ heat treatment process gas is treated atthe site of the formation to produce hydrogen. Treatment processes toproduce hydrogen from the in situ heat treatment process gas may includesteam methane reforming, autothermal reforming, and/or partial oxidationreforming.

All or at least a portion of a gas stream may be treated to yield a gasthat meets natural gas pipeline specifications. FIGS. 5, 6, 7, 8, and 9depict schematic representations of embodiments of systems for producingpipeline gas from the in situ heat treatment process gas stream.

As depicted in FIG. 5, in situ heat treatment process gas 240 entersunit 242. In unit 242, treatment of in situ heat treatment process gas240 removes sulfur compounds, carbon dioxide, and/or hydrogen to producegas stream 244. Unit 242 may include a physical treatment system and/ora chemical treatment system. The physical treatment system includes, butis not limited to, a membrane unit, a pressure swing adsorption unit, aliquid absorption unit, and/or a cryogenic unit. The chemical treatmentsystem may include units that use amines (for example, diethanolamine ordi-isopropanolamine), zinc oxide, sulfolane, water, or mixtures thereofin the treatment process. In some embodiments, unit 242 uses a Sulfinolgas treatment process for removal of sulfur compounds. Carbon dioxidemay be removed using Catacarb® (Catacarb, Overland Park, Kans., U.S.A.)and/or Benfield (UOP, Des Plaines, Ill., U.S.A.) gas treatmentprocesses.

Gas stream 244 may include, but is not limited to, hydrogen, carbonmonoxide, methane, and hydrocarbons having a carbon number of at least 2or mixtures thereof. In some embodiments, gas stream 244 includesnitrogen and/or rare gases such as argon or helium. In some embodiments,gas stream 244 includes from about 0.0001 grams (g) to about 0.1 g, fromabout 0.001 g to about 0.05 g, or from about 0.01 g to about 0.03 g ofhydrogen, per gram of gas stream. In certain embodiments, gas stream 244includes from about 0.01 g to about 0.6 g, from about 0.1 g to about 0.5g, or from about 0.2 g to 0.4 g of methane, per gram of gas stream.

In some embodiments, gas stream 244 includes from about 0.00001 g toabout 0.01 g, from about 0.0005 g to about 0.005 g, or from about 0.0001g to about 0.001 g of carbon monoxide, per gram of gas stream. Incertain embodiments, gas stream 244 includes trace amounts of carbondioxide.

In certain embodiments, gas stream 244 may include from about 0.0001 gto about 0.5 g, from about 0.001 g to about 0.2 g, or from about 0.01 gto about 0.1 g of hydrocarbons having a carbon number of at least 2, pergram of gas stream. Hydrocarbons having a carbon number of at least 2include paraffins and olefins. Paraffins and olefins include, but arenot limited to, ethane, ethylene, acetylene, propane, propylene,butanes, butylenes, or mixtures thereof. In some embodiments,hydrocarbons having a carbon number of at least 2 include from about0.0001 g to about 0.5 g, from about 0.001 g to about 0.2 g, or fromabout 0.01 g to about 0.1 g of a mixture of ethylene, ethane, andpropylene. In some embodiments, hydrocarbons having a carbon number ofat least 2 includes trace amounts of hydrocarbons having a carbon numberof at least 4.

Pipeline gas (for example, natural gas) after treatment to remove thehydrogen sulfide, includes methane, ethane, propane, butane, carbondioxide, oxygen, nitrogen, and small amounts of rare gases. Typically,treated natural gas includes, per gram of natural gas, about 0.7 g toabout 0.98 g of methane; about 0.0001 g to about 0.2 g or from about0.001 g to about 0.05 g of a mixture of ethane, propane, and butane;about 0.0001 g to about 0.8 g or from about 0.001 g to about 0.02 g ofcarbon dioxide; about 0.00001 g to about 0.02 g or from about 0.0001 toabout 0.002 of oxygen; trace amounts of rare gases; and the balancebeing nitrogen. Such treated natural gas has a heat content of about 40MJ/Nm³ to about 50 MJ/Nm³.

Since gas stream 244 differs in composition from treated natural gas,gas stream 244 may not meet pipeline gas requirements. Emissionsgenerated during burning of gas stream 244 may be unacceptable and/ornot meet regulatory standards if the gas stream is to be used as a fuel.Gas stream 244 may include components or amounts of components that makethe gas stream undesirable for use as a feed stream for makingadditional products.

In some embodiments, hydrocarbons having a carbon number greater than 2are separated from gas stream 244. These hydrocarbons may be separatedusing cryogenic processes, adsorption processes, and/or membraneprocesses. Removal of hydrocarbons having a carbon number greater than 2from gas stream 244 may facilitate and/or enhance further processing ofthe gas stream.

Process units as described herein may be operated at the followingtemperatures, pressures, hydrogen source flows, and gas stream flows, oroperated otherwise as known in the art. Temperatures may range fromabout 50° C. to about 600° C., from about 100° C. to about 500° C., orfrom about 200° C. to about 400° C. Pressures may range from about 0.1MPa to about 20 MPa, from about 1 MPa to about 12 MPa, from about 4 MPato about 10 MPa, or from about 6 MPa to about 8 MPa. Flows of gasstreams through units described herein may range from about 5 metrictons of gas stream per day (“MT/D”) to about 15,000 MT/D. In someembodiments, flows of gas streams through units described herein rangefrom about 10 MT/D to 10,000 MT/D or from about 15 MT/D to about 5,000MT/D. In some embodiments, the hourly volume of gas processed is 5,000to 25,000 times the volume of catalyst in one or more processing units.

As depicted in FIG. 5, gas stream 244 and hydrogen source 246 enterhydrogenation unit 248. Hydrogen source 246 includes, but is not limitedto, hydrogen gas, hydrocarbons, and/or any compound capable of donatinga hydrogen atom. In some embodiments, hydrogen source 246 is mixed withgas stream 244 prior to entering hydrogenation unit 248. In someembodiments, the hydrogen source is hydrogen and/or hydrocarbons presentin gas stream 244. In hydrogenation unit 248, contact of gas stream 244with hydrogen source 246 in the presence of one or more catalystshydrogenates unsaturated hydrocarbons in gas stream 244 and produces gasstream 250. Gas stream 250 may include hydrogen and saturatedhydrocarbons such as methane, ethane, and propane. Hydrogenation unit248 may include a knock-out pot. The knock-out pot removes any heavyby-products 252 from the product gas stream.

Gas stream 250 exits hydrogenation unit 248 and enters hydrogenseparation unit 254. Hydrogen separation unit 254 is any suitable unitcapable of separating hydrogen from the incoming gas stream. Hydrogenseparation unit 254 may be a membrane unit, a pressure swing adsorptionunit, a liquid absorption unit, or a cryogenic unit. In certainembodiments, hydrogen separation unit 254 is a membrane unit. Hydrogenseparation unit 254 may include PRISM® membranes available from AirProducts and Chemicals, Inc. (Allentown, Pa., U.S.A.). The membraneseparation unit may be operated at a temperature ranging from about 50°C. to about 80° C. (for examples, at a temperature of about 66° C.). Inhydrogen separation unit 254, separation of hydrogen from gas stream 250produces hydrogen rich stream 256 and gas stream 258. Hydrogen richstream 256 may be used in other processes, or, in some embodiments, ashydrogen source 246 for hydrogenation unit 248.

In some embodiments, hydrogen separation unit 254 is a cryogenic unit.When hydrogen separation unit 254 is a cryogenic unit, gas stream 250may be separated into a hydrogen rich stream, a methane rich stream,and/or a gas stream that contains components having a boiling pointgreater than or equal to ethane.

In some embodiments, hydrogen content in gas stream 258 is acceptableand further separation of hydrogen from gas stream 258 is not needed.When the hydrogen content in gas stream 258 is acceptable, the gasstream may be suitable for use as pipeline gas.

Further removal of hydrogen from gas stream 258 may be desired. In someembodiments, hydrogen is separated from gas stream 258 using a membrane.An example of a hydrogen separation membrane is described in U.S. Pat.No. 6,821,501 to Matzakos et al, which is incorporated by reference asif fully set forth herein.

In some embodiments, a method of removing hydrogen from gas stream 258includes converting hydrogen to water. Gas stream 258 exits hydrogenseparation unit 254 and enters oxidation unit 260, as shown in FIG. 5.Oxidation source 262 also enters oxidation unit 260. In oxidation unit260, contact of gas stream 258 with oxidation source 26 produces gasstream 264. Gas stream 264 may include water produced as a result of theoxidation. The oxidation source may include, but is not limited to, pureoxygen, air, or oxygen enriched air. Since air or oxygen enriched airincludes nitrogen, monitoring the quantity of air or oxygen enriched airprovided to oxidation unit 260 may be desired to ensure the product gasmeets the desired pipeline specification for nitrogen. Oxidation unit260 includes, in some embodiments, a catalyst. Oxidation unit 260 is, insome embodiments, operated at a temperature in a range from about 50° C.to 500° C., from about 100° C. to about 400° C., or from about 200° C.to about 300° C.

Gas stream 264 exits oxidation unit 260 and enters dehydration unit 266.In dehydration unit 266, separation of water from gas stream 264produces pipeline gas 268 and water 270. Dehydration unit 266 may be,for example, a standard gas plant glycol dehydration unit and/ormolecular sieves.

In some embodiments, a change in the amount of methane in pipeline gasproduced from an in situ heat treatment process gas is desired. Theamount of methane in pipeline gas may be enhanced through removal ofcomponents and/or through chemical modification of components in the insitu heat treatment process gas.

FIG. 6 depicts a schematic representation of an embodiment to enhancethe amount of methane in pipeline gas through reformation andmethanation of the in situ heat treatment process gas.

Treatment of in situ heat treatment process gas as described hereinproduces gas stream 244. Gas stream 244, hydrogen source 246, and steamsource 272 enter reforming unit 274. In some embodiments, gas stream244, hydrogen source 246, and/or steam source 272 are mixed togetherprior to entering reforming unit 274. In some embodiments, gas stream244 includes an acceptable amount of a hydrogen source, and thusexternal addition of hydrogen source 246 is not needed. In reformingunit 274, contact of gas stream 244 with hydrogen source 246 in thepresence of one or more catalysts and steam source 272 produces gasstream 276. The catalysts and operating parameters may be selected suchthat reforming of methane in gas stream 244 is minimized. Gas stream 276includes methane, carbon monoxide, carbon dioxide, and/or hydrogen. Thecarbon dioxide in gas stream 276, at least a portion of the carbonmonoxide in gas stream 276, and at least a portion of the hydrogen ingas stream 276 is from conversion of hydrocarbons with a carbon numbergreater than 2 (for example, ethylene, ethane, or propylene) to carbonmonoxide and hydrogen. Methane in gas stream 276, at least a portion ofthe carbon monoxide in gas stream 276, and at least a portion of thehydrogen in gas stream 276 is from gas stream 244 and hydrogen source246.

Reforming unit 274 may be operated at temperatures and pressuresdescribed herein, or operated otherwise as known in the art. In someembodiments, reforming unit 274 is operated at temperatures ranging fromabout 250° C. to about 500° C. In some embodiments, pressures inreforming unit 274 range from about 1 MPa to about 5 MPa.

Removal of excess carbon monoxide in gas stream 276 to meet, forexample, pipeline specifications may be desired. Carbon monoxide may beremoved from gas stream 276 using a methanation process. Methanation ofcarbon monoxide produces methane and water. Gas stream 276 exitsreforming unit 274 and enters methanation unit 278. In methanation unit278, contact of gas stream 276 with a hydrogen source in the presence ofone or more catalysts produces gas stream 280. The hydrogen source maybe provided by hydrogen and/or hydrocarbons present in gas stream 276.In some embodiments, an additional hydrogen source is added to themethanation unit and/or the gas stream. Gas stream 280 may includewater, carbon dioxide, and methane.

Methanation unit 278 may be operated at temperatures and pressuresdescribed herein or operated otherwise as known in the art. In someembodiments, methanation unit 278 is operated at temperatures rangingfrom about 260° C. to about 320° C. In some embodiments, pressures inmethanation unit 278 range from about 1 MPa to about 5 MPa.

Carbon dioxide may be separated from gas stream 280 in carbon dioxideseparation unit 282. In some embodiments, gas stream 280 exitsmethanation unit 278 and passes through a heat exchanger prior toentering carbon dioxide separation unit 282. In carbon dioxideseparation unit 282, separation of carbon dioxide from gas stream 280produces gas stream 284 and carbon dioxide stream 286. In someembodiments, the separation process uses amines to facilitate theremoval of carbon dioxide from gas stream 280. Gas stream 284 includes,in some embodiments, at most 0.1 g, at most 0.08 g, at most 0.06, or atmost 0.04 g of carbon dioxide per gram of gas stream. In someembodiments, gas stream 284 is substantially free of carbon dioxide.

Gas stream 284 exits carbon dioxide separation unit 282 and entersdehydration unit 266. In dehydration unit 266, separation of water fromgas stream 284 produces pipeline gas 268 and water 270.

FIG. 7 depicts a schematic representation of an embodiment to enhancethe amount of methane in pipeline gas through concurrent hydrogenationand methanation of in situ heat treatment process gas. Hydrogenation andmethanation of carbon monoxide and hydrocarbons having a carbon numbergreater than 2 in the in situ heat treatment process gas producesmethane. Concurrent hydrogenation and methanation in one processing unitmay inhibit formation of impurities. Inhibiting the formation ofimpurities enhances production of methane from the in situ heattreatment process gas. In some embodiments, the hydrogen source contentof the in situ heat treatment process gas is acceptable and an externalsource of hydrogen is not needed.

Treatment of in situ heat treatment process gas as described hereinproduces gas stream 244. Gas stream 244 enters hydrogenation andmethanation unit 288. In hydrogenation and methanation unit 288, contactof gas stream 244 with a hydrogen source in the presence of a catalystor multiple catalysts produces gas stream 290. The hydrogen source maybe provided by hydrogen and/or hydrocarbons in gas stream 244. In someembodiments, an additional hydrogen source is added to hydrogenation andmethanation unit 288 and/or gas stream 244. Gas stream 290 may includemethane, hydrogen, and, in some embodiments, at least a portion of gasstream 244. In some embodiments, gas stream 290 includes from about 0.05g to about 1 g, from about 0.8 g to about 0.99 g, or from about 0.9 g to0.95 g of methane, per gram of gas stream. Gas stream 290 may include,per gram of gas stream, at most 0.1 g of hydrocarbons having a carbonnumber of at least 2 and at most 0.01 g of carbon monoxide. In someembodiments, gas stream 290 includes trace amounts of carbon monoxideand/or hydrocarbons having a carbon number of at least 2.

Hydrogenation and methanation unit 288 may be operated at temperatures,and pressures, described herein, or operated otherwise as known in theart. In some embodiments, hydrogenation and methanation unit 288 isoperated at a temperature ranging from about 200° C. to about 350° C. Insome embodiments, pressure in hydrogenation and methanation unit 288 isabout 2 MPa to about 12 MPa, about 4 MPa to about 10 MPa, or about 6 MPato about 8 MPa. In certain embodiments, pressure in hydrogenation andmethanation unit 288 is about 4 MPa.

The removal of hydrogen from gas stream 290 may be desired. Removal ofhydrogen from gas stream 290 may allow the gas stream to meet pipelinespecification and/or handling requirements.

In FIG. 7, gas stream 290 exits methanation unit 288 and enterspolishing unit 292. Carbon dioxide stream 294 also enters polishing unit292, or it mixes with gas stream 290 upstream of the polishing unit. Inpolishing unit 292, tcontact of the gas stream 290 with carbon dioxidestream 294 in the presence of one or more catalysts produces gas stream296. The reaction of hydrogen with carbon dioxide produces water andmethane. Gas stream 296 may include methane, water, and, in someembodiments, at least a portion of gas stream 290. In some embodiments,polishing unit 292 is a portion of hydrogenation and methanation unit288 with a carbon dioxide feed line.

Polishing unit 292 may be operated at temperatures and pressuresdescribed herein, or operated as otherwise known in the art. In someembodiments, polishing unit 292 is operated at a temperature rangingfrom about 200° C. to about 400° C. In some embodiments, pressure inpolishing unit 292 is about 2 MPa to about 12 MPa, about 4 MPa to about10 MPa, or about 6 MPa to about 8 MPa. In certain embodiments, pressurein polishing unit 292 is about 4 MPa.

Gas stream 296 enters dehydration unit 266. In dehydration unit 266,separation of water from gas stream 296 produces pipeline gas 268 andwater 270.

FIG. 8 depicts a schematic representation of an embodiment to enhancethe amount of methane in pipeline gas through concurrent hydrogenationand methanation of in situ heat treatment process gas in the presence ofexcess carbon dioxide and the separation of ethane and heavierhydrocarbons. Hydrogen not used in the hydrogenation methanation processmay react with carbon dioxide to form water and methane. Water may thenbe separated from the process stream. Concurrent hydrogenation andmethanation in the presence of carbon dioxide in one processing unit mayinhibit formation of impurities.

Treatment of in situ heat treatment process gas as described hereinproduces gas stream 244. Gas stream 244 and carbon dioxide stream 294enter hydrogenation and methanation unit 298. In hydrogenation andmethanation unit 298, contact of gas stream 244 with a hydrogen sourcein the presence of one or more catalysts and carbon dioxide produces gasstream 300. The hydrogen source may be provided by hydrogen and/orhydrocarbons in gas stream 244. In some embodiments, the hydrogen sourceis added to hydrogenation and methanation unit 298 or to gas stream 244.The quantity of hydrogen in hydrogenation and methanation unit 298 maybe controlled and/or the flow of carbon dioxide may be controlled toprovide a minimum quantity of hydrogen in gas stream 300.

Gas stream 300 may include water, hydrogen, methane, ethane, and, insome embodiments, at least a portion of the hydrocarbons having a carbonnumber greater than 2 from gas stream 244. In some embodiments, gasstream 300 includes from about 0.05 g to about 0.7 g, from about 0.1 gto about 0.6 g, or from about 0.2 g to 0.5 g of methane, per gram of gasstream. Gas stream 300 includes from about 0.0001 g to about 0.4 g, fromabout 0.001 g to about 0.2 g, or from about 0.01 g to 0.1 g of ethane,per gram of gas stream. In some embodiments, gas stream 300 includes atrace amount of carbon monoxide and olefins.

Hydrogenation and methanation unit 298 may be operated at temperaturesand pressures, described herein, or operated otherwise as known in theart. In some embodiments, hydrogenation and methanation unit 298 isoperated at a temperature ranging from about 60° C. to about 350° C. anda pressure ranging from about 1 MPa to about 12 MPa, about 2 MPa toabout 10 MPa, or about 4 MPa to about 8 MPa.

In some embodiments, separation of ethane from methane is desirable.Separation may be performed using membrane and/or cryogenic techniques.Cryogenic processes may require that water levels in a gas stream be atmost 1-part per million by weight.

Water in gas stream 300 may be removed using generally known waterremoval techniques. Gas stream 300 exits hydrogenation and methanationunit 298, passes through heat exchanger 302 and then enters dehydrationunit 266. In dehydration unit 266, separation of water from gas stream300 as previously described, as well as by contact with absorption unitsand/or molecular sieves, produces gas stream 304 and water 270. Gasstream 304 may have a water content of at most 10 ppm, at most 5 ppm, orat most 1 ppm. In some embodiments, water content in gas stream 304ranges from about 0.01 ppm to about 10 ppm, from about 0.05 ppm to about5 ppm, or from about 0.1 ppm to about 1 ppm.

Cryogenic separator 306 separates gas stream 304 into pipeline gas 268and hydrocarbon stream 308. Pipeline gas stream 268 includes methaneand/or carbon dioxide. Hydrocarbon stream 308 includes ethane and, insome embodiments, residual hydrocarbons having a carbon number of atleast 2. In some embodiments, hydrocarbons having a carbon number of atleast 2 may be separated into ethane and additional hydrocarbons and/orsent to other operating units.

FIG. 9 depicts a schematic representation of an embodiment to enhancethe amount of methane in pipeline gas through concurrent hydrogenationand methanation of in situ heat treatment process gas in the presence ofexcess hydrogen. The use of excess hydrogen during the hydrogenation andmethanation process may prolong catalyst life, control reaction rates,and/or inhibit formation of impurities.

Treatment of in situ heat treatment process gas as described hereinproduces gas stream 244. Gas stream 244 and hydrogen source 246 enterhydrogenation and methanation unit 310. In some embodiments, hydrogensource 246 is added to gas stream 244. In hydrogenation and methanationunit 310, contact of gas stream 244 with hydrogen source 246 in thepresence of one or more catalysts produces gas stream 312. In someembodiments, carbon dioxide may be added to hydrogen and methanationunit 310. The quantity of hydrogen in hydrogenation and methanation unit310 may be controlled to provide an excess quantity of hydrogen to thehydrogenation and methanation unit.

Gas stream 312 may include water, hydrogen, methane, ethane, and, insome embodiments, at least a portion of the hydrocarbons having a carbonnumber greater than 2 from gas stream 244. In some embodiments, gasstream 312 includes from about 0.05 g to about 0.9 g, from about 0.1 gto about 0.6 g, or from about 0.2 g to 0.5 g of methane, per gram of gasstream. Gas stream 312 includes from about 0.0001 g to about 0.4 g, fromabout 0.001 g to about 0.2 g, or from about 0.01 g to 0.1 g of ethane,per gram of gas stream. In some embodiments, gas stream 312 includescarbon monoxide and trace amounts of olefins.

Hydrogenation and methanation unit 310 may be operated at temperaturesand pressures, described herein, or operated otherwise as known in theart. In some embodiments, hydrogenation and methanation unit 310 isoperated at a temperature ranging from about 60° C. to about 400° C. anda hydrogen partial pressure ranging from about 1 MPa to about 12 MPa,about 2 MPa to about 8 MPa, or about 3 MPa to about 5 MPa. In someembodiments, the hydrogen partial pressure in hydrogenation andmethanation unit 310 is about 3 MPa.

Gas stream 312 enters gas separation unit 314. Gas separation unit 314is any suitable unit or combination of units that is capable ofseparating hydrogen and/or carbon dioxide from gas stream 312. Gasseparation unit may be a pressure swing adsorption unit, a membraneunit, a liquid absorption unit, and/or a cryogenic unit. In someembodiments, gas stream 312 exits hydrogenation and methanation unit 310and passes through a heat exchanger prior to entering gas separationunit 314. In gas separation unit 314, separation of hydrogen from gasstream 312 produces gas stream 316 and hydrogen stream 318. Hydrogenstream 318 may be recycled to hydrogenation and methanation unit 310,mixed with gas stream 244 and/or mixed with hydrogen source 246 upstreamof the hydrogenation methanation unit. In embodiments in which carbondioxide is added to hydrogenation and methanation unit 310, carbondioxide is separated from gas stream 316 in separation unit 314. Theseparated carbon dioxide may be recycled to the hydrogenation andmethanation unit, mixed with gas stream 244 upstream of thehydrogenation and methanation unit, and/or mixed with the carbon dioxidestream entering the hydrogenation and methanation unit.

Gas stream 316 enters dehydration unit 266. In dehydration unit 266,separation of water from gas stream 316 produces pipeline gas 268 andwater 270.

It should be understood that gas stream 244 may be treated bycombinations of one or more of the processes described in FIGS. 5, 6, 7,8, and 9. For example, all or at least a portion of gas streams fromreforming unit 274 (FIG. 6) may be treated in hydrogenation andmethanation units 288 (FIG. 7), 298 (FIG. 8), or 308 (FIG. 9). All or atleast a portion of the gas stream produced from hydrogenation unit 248may enter, or be combined with gas streams entering, reforming unit 274,hydrogenation and methanation unit 288, and/or hydrogenation andmethanation unit 298. In some embodiments, gas stream 244 may behydrotreated and/or used in other processing units.

Catalysts used to produce natural gas that meets pipeline specificationsmay be bulk metal catalysts or supported catalysts. Bulk metal catalystsinclude Columns 6-10 metals. Supported catalysts include Columns 6-10metals on a support. Columns 6-10 metals include, but are not limitedto, vanadium, chromium, molybdenum, tungsten, manganese, technetium,rhenium, iron, cobalt, nickel, ruthenium, palladium, rhodium, osmium,iridium, platinum, or mixtures thereof. The catalyst may have, per gramof catalyst, a total Columns 6-10 metals content of at least 0.0001 g,at least 0.001 g, at least 0.01 g, or in a range from about 0.0001-0.6g, about 0.005-0.3 g, about 0.001-0.1 g, or about 0.01-0.08 g. In someembodiments, the catalyst includes a Column 15 element in addition tothe Columns 6-10 metals. An example of a Column 15 element isphosphorus. The catalyst may have a total Column 15 elements content,per gram of catalyst, in a range from about 0.000001-0.1 g, about0.00001-0.06 g, about 0.00005-0.03 g, or about 0.0001-0.001 g. In someembodiments, the catalyst includes a combination of Column 6 metals withone or more Columns 7-10 metals. A molar ratio of Column 6 metals toColumns 7-10 metals may be in a range from 0.1-20, 1-10, or 2-5. In someembodiments, the catalyst includes Column 15 elements in addition to thecombination of Column 6 metals with one or more Columns 7-10 metals.

In some embodiments, Columns 6-10 metals are incorporated in, ordeposited on, a support to form the catalyst. In certain embodiments,Columns 6-10 metals in combination with Column 15 elements areincorporated in, or deposited on, the support to form the catalyst. Inembodiments in which the metals and/or elements are supported, theweight of the catalyst includes all support, all metals, and allelements. The support may be porous and may include refractory oxides;oxides of tantalum, niobium, vanadium, scandium, or lanthanide metals;porous carbon based materials; zeolites; or combinations thereof.Refractory oxides may include, but are not limited to, alumina, silica,silica-alumina, titanium oxide, zirconium oxide, magnesium oxide, ormixtures thereof Supports may be obtained from a commercial manufacturersuch as CRI/Criterion Inc. (Houston, Tex., U.S.A.). Porous carbon basedmaterials include, but are not limited to, activated carbon and/orporous graphite. Examples of zeolites include Y-zeolites, beta zeolites,mordenite zeolites, ZSM-5 zeolites, and ferrierite zeolites. Zeolitesmay be obtained from a commercial manufacturer such as Zeolyst (ValleyForge, Pa., U.S.A.).

Supported catalysts may be prepared using generally known catalystpreparation techniques. Examples of catalyst preparations are describedin U.S. Pat. No. 6,218,333 to Gabrielov et al.; U.S. Pat. No. 6,290,841to Gabrielov et al.; U.S. Pat. No. 5,744,025 to Boon et al., and U.S.Pat. No. 6,759,364 to Bhan, all of which are incorporated by referenceherein.

In some embodiments, the support is impregnated with metal to form thecatalyst. In certain embodiments, the support is heat treated attemperatures in a range from about 400° C. to about 1200° C., from about450° C. to about 1000° C., or from about 600° C. to about 900° C. priorto impregnation with a metal. In some embodiments, impregnation aids areused during preparation of the catalyst. Examples of impregnation aidsinclude a citric acid component, ethylenediaminetetraacetic acid (EDTA),ammonia, or mixtures thereof

The Columns 6-10 metals and support may be mixed with suitable mixingequipment to form a Columns 6-10 metals/support mixture. The Columns6-10 metals/support mixture may be mixed using suitable mixingequipment. Examples of suitable mixing equipment include tumblers,stationary shells or troughs, Muller mixers (batch type or continuoustype), impact mixers, and any other generally known mixer, or otherdevice, that will suitably provide the Columns 6-10 metals supportmixture. In certain embodiments, the materials are mixed until theColumns 6-10 metals are substantially homogeneously dispersed in thesupport.

In some embodiments, the catalyst is heat treated at temperatures from150-750° C., from 200-740° C., or from 400-730° C. after combining thesupport with the metal. In some embodiments, the catalyst is heattreated in the presence of hot air and/or oxygen rich air at atemperature in a range between 400° C. and 1000° C. to remove volatilematter and/or to convert at least a portion of the Columns 6-10 metalsto the corresponding metal oxide.

In other embodiments, a catalyst precursor is heat treated in thepresence of air at temperatures in a range from 35-500° C. for a periodof time in a range from 1-3 hours to remove a majority of the volatilecomponents without converting the Columns 6-10 metals to thecorresponding metal oxide. Catalysts prepared by such a method aregenerally referred to as “unclacined” catalysts. When catalysts areprepared in this manner, in combination with a sulfiding method, theactive metals may be substantially dispersed in the support.Preparations of such catalysts are described in U.S. Pat. No. 6,218,333to Gabrielov et al., and U.S. Pat. No. 6,290,841 to Gabrielov et al.

In some embodiments, the catalyst and/or a catalyst precursor issulfided to form metal sulfides (prior to use) using techniques known inthe art (for example, ACTICAT™ process, CRI International, Inc.(Houston, Tex., U.S.A.)).

In some embodiments, the catalyst is dried the sulfided. Alternatively,the catalyst may be sulfided in situ by contact of the catalyst with agas stream that includes sulfur-containing compounds. In situsulfurization may utilize either gaseous hyrogen sulfide in the presenceof hydrogen or liquid-phase sulfurizing agents such as organosulfurcompounds (including alkylsulfides, plysulfides, thiols, andsulfosxides). Ex-situ sulfurization processes are described in U.S. Pat.No. 5,468,372 to Seamans et al., and U.S. Pat. 5,688,736 to Seamans etal., all of which are incorporated by reference herein.

In some embodiments, a first type of catalyst (“first catalyst”)includes Columns 6-10 metals and the support. The first catalyst is, insome embodiments, an uncalcined catalyst. In some embodiments, the firstcatalyst includes molybdenum and nickel. In certain embodiments, thefirst catalyst includes phosphorus. In some embodiments, the firstcatalyst includes Columns 9-10 metals on a support. The Column 9 metalmay be cobalt and the Column 10 metal may be nickel. In someembodiments, the first catalyst includes Columns 10-11 metals. TheColumn 10 metal may be nickel and the Column 11 metal may be copper.

The first catalyst may assist in the hydrogenation of olefins toalkanes. In some embodiments, the first catalyst is used in thehydrogenation unit. The first catalyst may include at least 0.1 g, atleast 0.2 g, or at least 0.3 g of Column 10 metals per gram of support.In some embodiments, the Column 10 metal is nickel. In certainembodiments, the Column 10 metal is palladium and/or a mixed alloy ofplatinum and palladium. Use of a mixed alloy catalyst may enhanceprocessing of gas streams with sulfur containing compounds. In someembodiments, the first catalyst is a commercial catalyst. Examples ofcommercial first catalysts include, but are not limited to, Criterion424, DN-140, DN-200, and DN-3100, KL6566, KL6560, KL6562, KL6564,KL7756; KL7762, KL7763, KL7731, C-624, C654, all of which are availablefrom CRI/Criterion Inc.

In some embodiments, a second type of catalyst (“second catalyst”)includes Column 10 metal on a support. The Column 10 metal may beplatinum and/or palladium. In some embodiments, the catalyst includesabout 0.001 g to about 0.05 g, or about 0.01 g to about 0.02 g ofplatinum and/or palladium per gram of catalyst. The second catalyst mayassist in the oxidation of hydrogen to form water. In some embodiments,the second catalyst is used in the oxidation unit. In some embodiments,the second catalyst is a commercial catalyst. An example of commercialsecond catalyst includes KL87748, available from CRI/Criterion Inc.

In some embodiments, a third type of catalyst (“third catalyst”)includes Columns 6-10 metals on a support. In some embodiments, thethird catalyst includes Columns 9-10 metals on a support. The Column 9metal may be cobalt and the Column 10 metal may be nickel. In someembodiments, the content of nickel metal is from about 0.1 g to about0.3 g, per gram of catalyst. The support for a third catalyst mayinclude zirconia. The third catalyst may assist in the reforming ofhydrocarbons having a carbon number greater than 2 to carbon monoxideand hydrogen. The third catalyst may be used in the reforming unit. Insome embodiments, the third catalyst is a commercial catalyst. Examplesof commercial third catalysts include, but are not limited to, CRG-FRand/or CRG-LH available from Johnson Matthey (London, England).

In some embodiments, a fourth type of catalyst (“fourth catalyst”)includes Columns 6-10 metals on a support. In some embodiments, thefourth catalyst includes Column 8 metals in combination with Column 10metals on a support. The Column 8 metal may be ruthenium and the Column10 metal may be nickel, palladium, platinum, or mixtures thereof. Insome embodiments, the fourth catalyst support includes oxides oftantalum, niobium, vanadium, the lanthanides, scandium, or mixturesthereof. The fourth catalyst may be used to convert carbon monoxide andhydrogen to methane and water. In some embodiments, the fourth catalystis used in the methanation unit. In some embodiments, the fourthcatalyst is a commercial catalyst. Examples of commercial fourthcatalysts, include, but are not limited to, KATALCO® 11-4 and/orKATALCO® 11-4R available from Johnson Matthey.

In some embodiments, a fifth type of catalyst (“fifth catalyst”)includes Columns 6-10 metals on a support. In some embodiments, thefifth catalyst includes a Column 10 metal. The fifth catalyst mayinclude from about 0.1 g to about 0.99 g, from about 0.3 g to about 0.9g, from about 0.5 g to about 0.8 g, or from 0.6 g to about 0.7 g ofColumn 10 metal per gram of fifth catalyst. In some embodiments, theColumn 10 metal is nickel. In some embodiments, a catalyst that has atleast 0.5 g of nickel per gram of fifth catalyst has enhanced stabilityin a hydrogenation and methanation process. The fifth catalyst mayassist in the conversion of hydrocarbons and carbon dioxide to methane.The fifth catalyst may be used in hydrogenation and methanation unitsand/or polishing units. In some embodiments, the fifth catalyst is acommercial catalyst. An example of a commercial fifth catalyst isKL6524-T, available from CRI/Criterion Inc.

Heating a portion of the subsurface formation may cause the mineralstructure of the formation to change and form particles. The particlesmay be dispersed and/or become partially dissolved in the formationfluid. The particles may include metals and/or compounds of metals fromColumns 1-2 and Columns 4-13 of the Periodic Table (for example,aluminum, silicon, magnesium, calcium, potassium sodium, beryllium,lithium, chromium, magnesium, copper, zirconium, and so forth). Incertain embodiments, the particles include cenospheres. In someembodiments, the particles are coated, for example, with hydrocarbons ofthe formation fluid. In certain embodiments, the particles includezeolites.

A concentration of particles in formation fluid may range from about 1ppm to about 3000 ppm, from about 50 ppm to about 2000 ppm, or fromabout 100 ppm to about 1000 ppm. The size of particles may range fromabout 0.5 micrometers to about 200 micrometers, from about 5 micrometersto about 150 micrometers, from about 10 micrometers to about 100micrometers, or about 20 micrometers to about 50 micrometers.

In certain embodiments, formation fluid may include a distribution ofparticles. The distribution of particles may be, but is not limited to,a trimodal or a bimodal distribution. For example, a trimodaldistribution of particles may include from about 1 ppm to about 50 ppmof particles with a size of about 5 micrometers to about 10 micrometers,from about 2 ppm to about 2000 ppm of particles with a size of about 50micrometers to about 80 micrometers, and from about I ppm to about 100ppm with a size of between about 100 micrometers and about 200micrometers. A bimodal distribution of particles may include from aboutI ppm to about 60 ppm of particles with a size of between about 50micrometers and about 60 micrometers and from about 2 ppm to about 2000ppm of particles with a size between about 100 micrometers and about 200micrometers.

In some embodiments, the particles may contact the formation fluid andcatalyze formation of compounds having a carbon number of at most 25, atmost 20, at most 12, or at most 8. In certain embodiments, zeoliticparticles may assist in the oxidation and/or reduction of formationfluids to produce compounds not generally found in fluids produced usingconventional production methods. Contact of formation fluid withhydrogen in the presence of zeolitic particles may catalyze reduction ofdouble bond compounds in the formation fluid.

In some embodiments, all or a portion of the particles in the producedfluid may be removed from the produced fluid. The particles may beremoved by using a centrifuge, by washing, by acid washing, byfiltration, by electrostatic precipitation, by froth flotation, and/orby another type of separation process.

Formation fluid produced from the in situ heat treatment process may besent to the separator to split the stream into the in situ heattreatment process liquid stream and an in situ heat treatment processgas stream. The liquid stream and the gas stream may be further treatedto yield desired products. When the liquid stream is treated usinggenerally known conditions to produce commercial products, processingequipment may be adversely affected. For example, the processingequipment may clog. Examples of processes to produce commercial productsinclude, but are not limited to, alkylation, distillation, catalyticreforming hydrocracking, hydrotreating, hydrogenation,hydrodesulfurization, catalytic cracking, delayed coking, gasification,or combinations thereof Processes to produce commercial products aredescribed in “Refining Processes 2000,” Hydrocarbon Processing, GulfPublishing Co., pp. 87-142, which is incorporated by reference herein.Examples of commercial products include, but are not limited to, diesel,gasoline, hydrocarbon gases, jet fuel, kerosene, naphtha, vacuum gas oil(“VGO”), or mixtures thereof.

Process equipment may become clogged or fouled by compositions in the insitu heat treatment process liquid. Clogging compositions may include,but are not limited to, hydrocarbons and/or solids produced from the insitu heat treatment process. Compositions that cause clogging may beformed during heating of the in situ heat treatment process liquid. Thecompositions may adhere to parts of the equipment and inhibit the flowof the liquid stream through processing units.

Solids that cause clogging may include, but are not limited to,organometallic compounds, inorganic compounds, minerals, mineralcompounds, cenospheres, coke, semi-soot, and/or mixtures thereof. Thesolids may have a particle size such that conventional filtration maynot remove the solids from the liquid stream. Hydrocarbons that causeclogging may include, but are not limited to, hydrocarbons that containheteroatoms, aromatic hydrocarbons, cyclic hydrocarbons, cyclicdi-olefins, and/or acyclic di-olefins. In some embodiments, solidsand/or hydrocarbons present in the in situ heat treatment process liquidthat cause clogging are partially soluble or insoluble in the situ heattreatment process liquid. In some embodiments, conventional filtrationof the liquid stream prior to or during heating is insufficient and/orineffective for removal of all or some of the compositions that clogprocess equipment.

In some embodiments, clogging compositions are at least partiallyremoved from the liquid stream by washing and/or desalting the liquidstream. In some embodiments, clogging of process equipment is inhibitedby filtering at least a portion of the liquid stream through ananofiltration system. In some embodiments, clogging of processequipment is inhibited by hydrotreating at least a portion of the liquidstream. In some embodiments, at least a portion the liquid stream isnanofiltered and then hydrotreated to remove composition that may clogand/or foul process equipment. The hydrotreated and/or nanofilteredliquid stream may be further processed to produce commercial products.In some embodiments, anti-fouling additives are added to the liquidstream to inhibit clogging of process equipment. Anti-fouling additivesare described in U.S. Pat. No. 5,648,305 to Mansfield et al.; U.S. Pat.No. 5,282,957 to Wright et al.; U.S. Pat. No. 5,173,213 to Miller etal.; U.S. Pat. No. 4,840,720 to Reid; U.S. Pat. No. 4,810,397 toDvoracek; and U.S. Pat. No. 4,551,226 to Fern, all of which areincorporated by reference herein. Examples of commercially availableadditives include, but are not limited to, Chimec RO 303 Chimec RO 304,Chimec RO 305, Chimec RO 306, Chimec RO 307, Chimec RO 308, (availablefrom Chimec, Rome, Italy), GE-Betz Thermal Flow 7R29 GE-Betz ProChem3F28, Ge Betz ProChem 3F 18 (available from GE Water and ProcessTechnologies, Trevose, Pa., U.S.A.).

FIG. 10 depicts a schematic representation of an embodiment of a systemfor producing crude products and/or commercial products from the in situheat treatment process liquid stream and/or the in situ heat treatmentprocess gas stream. Formation fluid 320 enters fluid separation unit 322and is separated into in situ heat treatment process liquid stream 324,in situ heat treatment process gas 240 and aqueous stream 326. In someembodiments, fluid separation unit 322 includes a quench zone. Asproduced formation fluid enters the quench zone, quenching fluid such aswater, nonpotable water and/or other components may be added to theformation fluid to quench and/or cool the formation fluid to atemperature suitable for handling in downstream processing equipment.Quenching the formation fluid may inhibit formation of compounds thatcontribute to physical and/or chemical instability of the fluid (forexample, inhibit formation of compounds that may precipitate fromsolution, contribute to corrosion, and/or fouling of downstreamequipment and/or piping). The quenching fluid may be introduced into theformation fluid as a spray and/or a liquid stream. In some embodiments,the formation fluid is introduced into the quenching fluid. In someembodiments, the formation fluid is cooled by passing the fluid througha heat exchanger to remove some heat from the formation fluid. Thequench fluid may be added to the cooled formation fluid when thetemperature of the formation fluid is near or at the dew point of thequench fluid. Quenching the formation fluid near or at the dew point ofthe quench fluid may enhance solubilization of salts that may causechemical and/or physical instability of the quenched fluid (for example,ammonium salts). In some embodiments, an amount of water used in thequench is minimal so that salts of inorganic compounds and/or othercomponents do not separate from the mixture. In separation unit 322, atleast a portion of the quench fluid may be separated from the quenchmixture and recycled to the quench zone with a minimal amount oftreatment. Heat produced from the quench may be captured and used inother facilities. In some embodiments, vapor may be produced during thequench. The produced vapor may be sent to gas separation unit 328 and/orsent to other facilities for processing.

In situ heat treatment process gas 240 may enter gas separation unit 328to separate gas hydrocarbon stream 330 from the in situ heat treatmentprocess gas. The gas separation unit is, in some embodiments, arectified adsorption and high pressure fractionation unit. Gashydrocarbon stream 330 includes hydrocarbons having a carbon number ofat least 3.

In situ heat treatment process liquid stream 324 enters liquidseparation unit 332. In some embodiments, liquid separation unit 332 isnot necessary. In liquid separation unit 332, separation of in situ heattreatment process liquid stream 324 produces gas hydrocarbon stream 336and salty process liquid stream 338. Gas hydrocarbon stream 336 mayinclude hydrocarbons having a carbon number of at most 5. A portion ofgas hydrocarbon stream 336 may be combined with gas hydrocarbon stream330. Salty process liquid stream 338 may be processed through desaltingunit 340 to form liquid stream 334. Desalting unit 340 removes mineralsalts and/or water from salty process liquid stream 338 using knowndesalting and water removal methods. In certain embodiments, desaltingunit 340 is upstream of liquid separation unit 332.

Liquid stream 334 includes, but is not limited to, hydrocarbons having acarbon number of at least 5 and/or hydrocarbon containing heteroatoms(for example, hydrocarbons containing nitrogen, oxygen, sulfur, andphosphorus). Liquid stream 334 may include at least 0.001 g, at least0.005 g, or at least 0.01 g of hydrocarbons with a boiling rangedistribution between 95° C. and 200° C. at 0.101 MPa; at least 0.01 g,at least 0.005 g, or at least 0.001 g of hydrocarbons with a boilingrange distribution between 200° C. and 300° C. at 0.101 MPa; at least0.001 g, at least 0.005 g, or at least 0.01 g of hydrocarbons with aboiling range distribution between 300° C. and 400° C. at 0.101 MPa; andat least 0.001 g at least 0.005 g, or at least 0.01 g of hydrocarbonswith a boiling range distribution between 400° C. and 650° C. at 0.101MPa. In some embodiments, liquid stream 334 contains at most 10% byweight water, at most 5% by weight water, at most 1% by weight water, orat most 0.1% by weight water.

After exiting desalting unit 340, liquid stream 334 enters filtrationsystem 342. In some embodiments, filtration system 342 is connected tothe outlet of the desalting unit. Filtration system 342 separates atleast a portion of the clogging compounds from liquid stream 334. Insome embodiments, filtration system 342 is skid mounted. Skid mountingfiltration system 342 may allow the filtration system to be moved fromone processing unit to another. In some embodiments, filtration system342 includes one or more membrane separators, for example, one or morenanofiltration membranes or one or more reverse osmosis membranes.

The membrane may be a ceramic membrane and/or a polymeric membrane. Theceramic membrane may be a ceramic membrane having a molecular weight cutoff of at most 2000 Daltons (Da), at most 1000 Da, or at most 500 Da.Ceramic membranes do not have to swell in order to work under optimalconditions to remove the desired materials from a substrate (forexample, clogging compositions from the liquid stream). In addition,ceramic membranes may be used at elevated temperatures. Examples ofceramic membranes include, but are not limited to, mesoporous titania,mesoporous gamma-alumina, mesoporous zirconia, mesoporous silica, andcombinations thereof.

The polymeric membrane includes a top layer made of a dense membrane anda base layer (support) made of a porous membrane. The polymeric membranemay be arranged to allow the liquid stream (permeate) to flow firstthrough the dense membrane top layer and then through he base layer sothat the pressure difference over the membrane pushes the top layer ontothe base layer. The polymeric membrane is an organophilic or hydrophobicmembrane so that water present in the liquid stream is retained orsubstantially retained in the retentate.

The dense membrane layer may separate at least a portion of orsubstantially all of the clogging compositions from liquid stream 334.In some embodiments, the dense polymeric membrane has properties suchthat liquid stream 334 passes through the membrane by dissolving in anddiffusing through its structure. At least a portion of the cloggingparticles may not dissolve and/or diffuse through the dense membrane,thus they are removed. The clogging particles may not dissolve and/ordiffuse through the dense membrane because of the complex structure ofthe clogging particles and/or their high molecular weight. The densemembrane layer may include a cross-linked structure as described in WO96/27430 to Schmidt et al., which is incorporated by reference herein. Athickness of the dense membrane layer may range from a 1 micrometer to15 micrometers, from 2 micrometers to 10 micrometers, or from 3micrometers to 5 micrometers.

The dense membrane may be made from polysiloxane, poly-di-methylsiloxane, poly-octyl-methyl siloxane, polyimide, polyaramide,poly-tri-methyl silyl propyne, or mixtures thereof Porous base layersmay be made of materials that provide mechanical strength to themembrane and may be any porous membrane used for ultra filtration,nanofiltration, or reverse osmosis. Examples of such materials arepolyacrylonitrile, polyamideimide in combination with titanium oxide,polyetherimide, polyvinylidenediflouroide, polytetrafluoroethylene orcombinations thereof.

During separation of clogging compositions from liquid stream 334, thepressure difference across the membrane may range from about 0.5 MPa toabout 6 MPa, from about 1 MPa to about 5 MPa, or from about 2 MPa toabout 4 MPa. A temperature of separation may range from the pour pointof the liquid stream up to 100° C., from about −20° C. to about 100° C.,from about 10° C. to about 90° C., or from about 20° C. to 85° C. Duringa continous operation, the permeate flux rate may be at most 50% of theinitial flux, at most 70% of the initial flux, or at most 90% of theinitial flux. A weight recovery of the permeate on feed may range fromabout 50% by weight to 97% by weight, from about 60% by weight to 90% byweight, or from about 70% by weight to 80% by weight.

Filtration system 342 may include one or more membrane separators. Themembrane separators may include one or more membrane modules. When twoor more membrane separators are used, they may be arranged in a parallelconfiguration to allow feed (retentate) from a first membrane separatorto flow into a second membrane separator. Examples of membrane modulesinclude, but are not limited to, spirally wound modules, plate and framemodules, hollow fibers, and tubular modules. Membrane modules aredescribed in Encyclopedia of Chemical Engineering, 4^(th) Ed., 1995,John Wiley & Sons Inc., Vol. 16, pages 158-164. Examples of spirallywound modules are described in, for example, WO/2006/040307 to Boestertet al., U.S. Pat. No. 5,102,551 to Pasternak; U.S. Pat. No. 5,093,002 toPasternak; U.S. Pat. No. 5,275,726 to Feimer et al.; U.S. Pat. No.5,458,774 to Mannapperuma; and U.S. Pat. No. 5,150,118 to Finkle et al,all of which are incorporated by reference herein.

In some embodiments, a spirally wound module is used when a densemembrane is used in filtration system 342. A spirally wound module mayinclude a membrane assembly of two membrane sheets between which apermeate spacer sheet is sandwiched, and which membrane assembly issealed at three sides. The fourth side is connected to a permeate outletconduit such that the area between the membranes in fluid communicationwith the interior of the conduit. On top of one of the membranes a feedspacer sheet is arranged, and the assembly with feed spacer sheet isrolled up around the permeate outlet conduit, to form a substantiallycylindrical spirally wound membrane module. The feed spacer may have athickness of at least 0.6 mm, at least 1 mm, or at least 3 mm to allowsufficient membrane surface to be packed into a spirally wound module.In some embodiments, the feed spacer is a woven feed spacer. Duringoperation, a feed mixture may be passed from one end of the cylindricalmodule between the membrane assemblies along the feed spacer sheetsandwiched between feed sides of the membranes. Part of the feed mixturepasses through either one of the membrane sheets to the permeate side.The resulting permeate flows along the permeate spacer sheet into thepermeate outlet conduit.

In some embodiments, the membrane separation is a continuous process.Liquid stream 334 passes over the membrane due to a pressure differenceto obtain a filtered liquid stream 344 (permeate) and/or recycle liquidstream 346 (retentate). In some embodiments, filtered liquid stream 344may have reduced concentrations of compositions and/or particles thatcause clogging in downstream processing systems. Continuous recycling ofrecycle liquid stream 346 through nanofiltration system can increase theproduction of filtered liquid stream 344 to as much as 95% of theoriginal volume of liquid stream 334. Recycle liquid stream 346 may becontinuously recycled through a spirally wound membrane module for atleast 10 hours, for at least one day, or for at least one week withoutcleaning the feed side of the membrane. Upon completion of thefiltration, waste stream 348 (retentate) may include a highconcentration of compositions and/or particles that cause clogging.Waste stream 348 exits filtration system 342 and is transported to otherprocessing units such as, for example, a delayed coking unit and/or agasification unit.

Filtered liquid stream 344 may exit filtration system 342 and enter oneor more process units. Process units as described herein for theproduction of crude products and/or commercial products may be operatedat the following temperatures, pressures, hydrogen source flows, liquidstream flows, or combinations thereof, or operated otherwise as known inthe art. Temperatures range from about 200° C. to about 900° C., fromabout 300° C. to about 800° C., or from about 400° C. to about 700° C.Pressures range from about 0.1 MPa to about 20 MPa, from about 1 MPa toabout 12 MPa, from about 4 MPa to about 10 MPa, or from about 6 MPa toabout 8 MPa. Liquid hourly space velocities of the liquid stream rangefrom about 0.1 h⁻¹ to about 30 h⁻¹, from about 0.5 h⁻¹ to about 25 h⁻¹,from about 1 h⁻¹ to about 20 h⁻¹, from about 1.5 h⁻¹ to about 15 h⁻¹, orfrom about 2 h⁻¹ to about 10 h⁻¹.

In FIG. 10, filtered liquid stream 344 and hydrogen source 246 enterhydrotreating unit 350. In some embodiments, hydrogen source 246 may beadded to filtered liquid stream 344 before entering hydrotreating unit350. In some embodiments, sufficient hydrogen is present in liquidstream 334 and hydrogen source 246 is not needed. In hydrotreating unit350, contact of filtered liquid stream 344 with hydrogen source 246 inthe presence of one or more catalysts produces liquid stream 352.Hydrotreating unit 350 may be operated such that all or at least aportion of liquid stream 352 is changed sufficiently to removecompositions and/or inhibit formation of compositions that may clogequipment positioned downstream of the hydrotreating unit 350. Thecatalyst used in hydrotreating unit 350 may be a commercially availablecatalyst. In some embodiments, hydrotreating of liquid stream 334 is notnecessary.

In some embodiments, liquid stream 334 is contacted with hydrogen in thepresence of one or more catalysts to change one or more desiredproperties of the crude feed to meet transportation and/or refineryspecifications. Methods to change one or more desired properties of thecrude feed are described in U.S. Published Patent Applications Nos.20050133414 to Bhan et al.; 20050133405 to Wellington et al.; and U.S.patent application Ser. No. 11/400,542 entitled “Systems, Methods, andCatalysts for Producing a Crude Product” filed Apr. 7, 2006; Ser. No.11/425,979 to Bhan entitled “Systems, Methods, and Catalysts forProducing a Crude Product” filed Jun. 6, 2006; and Ser. No. 11/425,992to Wellington et al., entitled “Systems, Methods, and Catalysts forProducing a Crude Product” filed Jun. 6, 2006, all of which areincorporated by reference herein.

In some embodiments, hydrotreating unit 350 is a selective hydrogenationunit. In hydrotreating unit 350, liquid stream 334 and/or filteredliquid stream 344 are selectively hydrogenated such that di-olefins arereduced to mono-olefins. For example, liquid stream 334 and/or filteredliquid stream 344 is contacted with hydrogen in the presence of a DN-200(Criterion Catalysts & Technologies, Houston Tex., U.S.A.) attemperatures ranging from 100° C. to 200° C. and total pressures of 0.1MPa to 40 MPa to produce liquid stream 352. Liquid stream 352 includes areduced content of di-olefins and an increased content of mono-olefinsrelative to the di-olefin and mono-olefin content of liquid stream 334.The conversion of di-olefins to mono-olefins under these conditions is,in some embodiments, at least 50%, at least 60%, at least 80% or atleast 90%. Liquid stream 352 exits hydrotreating unit 350 and enters oneor more processi units positioned downstream of hydrotreating unit 350.The units positioned downstream of hydrotreating unit 350 may includedistillation units, catalytic reforming units, hydrocracking units,hydrotreating units, hydrogenation units, hydrodesulfurization units,catalytic cracking units, delayed coking units, gasification units, orcombinations thereof.

Liquid stream 352 may exit hydrotreating unit 350 and enterfractionation unit 354. Fractionation unit 354 produces one or morecrude products. Fractionation may include, but is not limited to, anatmospheric distillation process and/or a vacuum distillation process.Crude products include, but are not limited to, C₃-C₅ hydrocarbon stream356, naphtha stream 358, kerosene stream 360, diesel stream 362, andbottoms stream 364. Bottoms stream 364 generally includes hydrocarbonshaving a boiling range distribution of at least 340° C. at 0.101 MPa. Insome embodiments, bottoms stream 364 is vacuum gas oil. In otherembodiments, bottoms stream 364 includes hydrocarbons with a boilingrange distribution of at least 537° C. One or more of the crude productsmay be sold and/or further processed to gasoline or other commercialproducts.

To enhance the use of the streams produced from formation fluid,hydrocarbons produced during fractionation of the liquid stream andhydrocarbon gases produced during separating the process gas may becombined to form hydrocarbons having a higher carbon number. Theproduced hydrocarbon gas stream may include a level of olefinsacceptable for alkylation reactions.

In some embodiments, hydrotreated liquid streams and/or streams producedfrom fractions (for example, distillates and/or naphtha) are blendedwith the in situ heat treatment process liquid and/or formation fluid toproduce a blended fluid. The blended fluid may have enhanced physicalstability and chemical stability as compared to the formation fluid. Theblended fluid may have a reduced amount of reactive species (forexample, di-olefins, other olefins and/or compounds containing oxygen,sulfur and/or nitrogen) relative to the formation fluid. Thus, chemicalstability of the blended fluid is enhanced. The blended fluid maydecrease an amount of asphaltenes relative to the formation fluid. Thus,physical stability of the blended fluid is enhanced. The blended fluidmay be a more a fungible feed than the formation fluid and/or the liquidstream produced from an in situ heat treatment process. The blended feedmay be more suitable for transportation, for use in chemical processingunits and/or for use in refining units than formation fluid.

In some embodiments, a fluid produced by methods described herein froman oil shale formation may be blended with heavy oil/tar sands in situheat treatment process (IHTP) fluid. Since the oil shale liquid issubstantially paraffinic and the heavy oil/tar sands IHTP fluid issubstantially aromatic, the blended fluid exhibits enhanced stability.In certain embodiments, in situ heat treatment process fluid may beblended with bitumen to obtain a feed suitable for use in refiningunits. Blending of the IHTP fluid and/or bitumen with the produced fluidmay enhance the chemical and/or physical stability of the blendedproduct. Thus, the blend may be transported and/or distributed toprocessing units.

C₃-C₅ hydrocarbon stream 356 produced from fractionation unit 354 andhydrocarbon gas stream 330 enter alkylation unit 368. In alkylation unit368, reaction of the olefins in hydrocarbon gas stream 330 (for example,propylene, butylenes, amylenes, or combinations thereof) with theiso-paraffins in C₃-C₅ hydrocarbon stream 356 produces hydrocarbonstream 370. In some embodiments, the olefin content in hydrocarbon gasstream 330 is acceptable and an additional source of olefins is notneeded. Hydrocarbon stream 370 includes hydrocarbons having a carbonnumber of at least 4. Hydrocarbons having a carbon number of at least 4include, but are not limited to, butanes, pentanes, hexanes, heptanes,and octanes. In certain embodiments, hydrocarbons produced fromalkylation unit 368 have an octane number greater than 70, greater than80, or greater than 90. In some embodiments, hydrocarbon stream 370 issuitable for use as gasoline without further processing.

In some embodiments, bottoms stream 364 may be hydrocracked to producenaphtha and/or other products. The resulting naphtha may, however, needreformation to alter the octane level so that the product may be soldcommercially as gasoline. Alternatively, bottoms stream 364 may betreated in a catalytic cracker to produce naphtha and/or feed for analkylation unit. In some embodiments, naphtha stream 358, kerosenestream 360, and diesel stream 362 have an imbalance of paraffinichydrocarbons, olefinic hydrocarbons, and/or aromatic hydrocarbons. Thestreams may not have a suitable quantity of olefins and/or aromatics foruse in commercial products. This imbalance may be changed by combiningat least a portion of the streams to form combined stream 366 which hasa boiling range distribution from about 38° C. to about 343° C.Catalytically cracking combined stream 366 may produce olefins and/orother streams suitable for use in an alkylation unit and/or otherprocessing units. In some embodiments, naphtha stream 358 ishydrocracked to produce olefins.

In FIG. 10, combined stream 366 and bottoms stream 364 fromfractionation unit 354 enters catalytic cracking unit 372. Undercontrolled cracking conditions (for example, controlled temperatures andpressures), catalytic cracking unit 372 produces additional C₃-C₅hydrocarbon stream 356′, gasoline hydrocarbons stream 374, andadditional kerosene stream 360′.

Additional C₃-C₅ hydrocarbon stream 356′ may be sent to alkylation unit368, combined with C₃-C₅ hydrocarbon stream 356, and/or combined withhydrocarbon gas stream 330 to produce gasoline suitable for commercialsale. In some embodiments, the olefin content in hydrocarbon gas stream330 is acceptable and an additional source of olefins is not needed.

In some embodiments, an amount of the produced bottoms stream (forexample, VGO) is too low to sustain operation of a hydrocracking unit orcatalytic cracking unit and the concentration of olefins in the producedgas streams from a fractionation unit and/or a catalytic cracking unit(for example, from fractionation unit 354 and/or from catalytic crackingunit 372 in FIG. 10) may be too low to sustain operation of analkylation unit. The naphtha produced from the fractionation unit may betreated to produce olefins for further processing in, for example, analkylation unit. Reformulated gasoline produced by conventional naphthareforming processes may not meet commercial specifications such as, forexample, California Air Resources Board mandates when liquid streamproduced from an in situ heat treatment process liquid is used as a feedstream. An amount of olefins in the naphtha may be saturated duringconventional hydrotreating prior to the reforming naphtha process. Thus,reforming of all the hydrotreated naphtha may result in a higher thandesired aromatics content in the gasoline pool for reformulatedgasoline. The imbalance in the olefin and aromatic content in thereformed naphtha may be changed by producing sufficient alkylate from analkylation unit to produce reformulated gasoline. Olefins (for example,propylene and butylenes) generated from fractionation and/or cracking ofthe naphtha may be combined with isobutane to produce gasoline. Inaddition, it has been found that catalytically cracking the naphthaand/or other fractionated streams produced in a fractionating unitrequires additional heat because of a reduced amount of coke productionrelative to other feedstocks used in catalytic cracking units.

FIG. 11 depicts a schematic for treating liquid streams produced from anin situ heat treatment process stream to produce olefins and/or liquidstreams. Similar processes to produce middle distillate and olefins aredescribed in International Publication No. WO 20061020547 and U.S.Patent Application Publication No. 20060191820 and 20060178546 to Mo etal., all of which are incorporated by referenced herein. Liquid stream376 enters catalytic cracking system 378. Liquid stream 376 may include,but is not limited to, liquid stream 334, hydrotreated liquid stream352, filtered liquid stream 344, naphtha stream 358, kerosene stream360, diesel stream 362, and bottoms stream 364 from the system depictedin FIG. 10, any hydrocarbon stream having a boiling range distributionbetween 65° C. and 800° C., or mixtures thereof. In some embodiments,steam 272 enters catalytic cracking system 378 and may atomize and/orlift liquid stream 376 to enhance contact of the liquid stream with thecatalytic cracking catalyst. A ratio of steam to atomize liquid stream376 to feedstock may range from 0.01 to 2 by weight, or from 0.1 to 1 byweight.

In catalytic cracking system 378, liquid stream 376 is contacted with acatalytic cracking catalyst to produce one or more crude products. Thecatalytic cracking catalyst includes a selected catalytic crackingcatalyst, at least a portion of used regenerated cracking catalyststream 380, at least a portion of a regenerated cracking catalyst stream382, or a mixture thereof. Used regenerated cracking catalyst 380includes a regenerated cracking catalyst that has been used in secondcatalytic cracking system 384. Second catalytic cracking system 384 maybe used to crack hydrocarbons to produce olefins and/or other crudeproducts. Hydrocarbons provided to second catalytic cracking system 384may include C₃-C₅ hydrocarbons produced from the production wells,gasoline hydrocarbons, hydrowax, hydrocarbons produced fromFischer-Tropsch processes, biofuels, or combinations thereof. The use ofa mixture of different types of hydrocarbon feed to the second catalyticcracking system may enhance C₃-C₅ olefin production to meet the alkylatedemand. Thus, integration of the products with refinery processes may beenhanced. Second catalytic cracking system 384 may be a dense phaseunit, a fixed fluidized bed unit, a riser, a combination of the abovementioned units, or any unit or configuration of units known in the artfor cracking hydrocarbons.

Contact of the catalytic cracking catalyst and the liquid stream 376 incatalytic cracking system 378 produces a crude product and spentcracking catalyst. The crude product may include, but is not limited to,hydrocarbons having a boiling point distribution that is less than theboiling point distribution of liquid stream 376, a portion of liquidstream 376, or mixtures thereof. The crude product and spent catalystenters separation system 386. Separation system 386 may include, forexample, a distillation unit, a stripper, a filtration system, acentrifuge, or any device known in the art capable of separating thecrude product from the spent catalyst.

Separated spent cracking catalyst stream 388 exits separation system 386and enters regeneration unit 390. In regeneration unit 390, spentcracking catalyst is contacted with oxygen source 392 (for example,oxygen and/or air) under carbon burning conditions to produceregenerated cracking catalyst stream 382 and combustion gases 394.Combustion gases may form as a by-product of the removal of carbonand/or other impurities formed on the catalyst during the catalyticcracking process.

The temperature in regeneration unit 390 may range from about 621° C. toabout 760° C. or from about 677° C. to about 715° C. The pressure inregeneration unit 390 may range from atmospheric to about 0.345 MPa orfrom about 0.034 to about 0.345 MPa. The residence time of the separatedspent cracking catalyst in regeneration unit 390 ranges from about 1 toabout 6 minutes or from or about 2 to about 4 minutes. The coke contenton the regenerated cracking catalyst is less than the coke content onthe separated spent cracking catalyst. Such coke content is less than0.5% by weight, with the weight percent being based on the weight of theregenerated cracking catalyst excluding the weight of the coke content.The coke content of the regenerated cracking catalyst may range from0.01% by weight to 0.5% by weight, 0.05% by weight to 0.3% by weight, or0.1% by weight to 0.2% by weight.

In some embodiments, regenerated cracking catalyst stream 382 may bedivided into two streams with at least a portion of regenerated crackingcatalyst stream 382′ exiting regeneration unit 390 and entering secondcatalytic cracking system 384. At least another portion of regeneratedcracking catalyst stream 382 exits regenerator 390 and enters catalyticcracking system 378. The relative amount of the used regeneratedcracking catalyst to the regenerated racking catalyst is adjusted toprovide for the desired cracking conditions within catalytic crackingsystem 378. Adjusting the ratio of used regenerated cracking catalyst toregenerated cracking catalyst may assist in the control of the crackingconditions in catalytic cracking system 378. A weight ratio of the usedregenerated cracking catalyst to the regenerated cracking catalyst mayrange from 0.1:1 to 100:1, from 0.5:1 to 20:1, or from 1:1 to 10:1. Fora system operated at steady state, the weight ratio of used regeneratedcracking catalyst to regenerated cracking catalyst approximates theweight ratio of the portion of regenerated cracking catalyst passing tothe second catalytic cracking system 384 to the remaining portion ofregenerated cracking catalyst that is mixed with liquid stream 376introduced into catalytic cracking system 378, and, thus, theaforementioned ranges are also applicable to such weight ratio.

Crude product 396 exits separation system 386 and enters liquidseparation unit 398. Liquid separation unit 398 may be any system knownto those skilled in the art for recovering and separating the crudeproduct into product streams such as, for example, gas stream 336′,gasoline hydrocarbons stream 400, cycle oil stream 402, and boftomstream 404. In some embodiments, bottom stream 404 is recycled tocatalytic cracking system 378. Liquid separation unit 398 may includecomponents and/or units such as, for example, absorbers and strippers,fractionators, compressors and separators, or any combination of knownsystems for providing recovery and separation of products from the crudeproduct. In some embodiments, at least a portion of light cycle oilstream 402 exits liquid separation unit 398 and enters second catalyticcracking system 384. In some embodiments, none of the light cycle oilstream is sent to the second catalytic cracking system. In someembodiments, at least a portion of gasoline hydrocarbons stream 400exits liquid separation unit 398 and enters second catalytic crackingsystem 384. In some embodiments, none of the gasoline hydrocarbonsstream is sent to the second catalytic cracking system. In someembodiments, gasoline hydrocarbons stream 400 is suitable for saleand/or for use in other processes.

At least a portion of gas oil hydrocarbon stream 406 (for example,vacuum gas oil) and/or portions of gasoline hydrocarbons stream 400 andat least a portion of light cycle oil stream 402 are sent to catalyticcracking system 384. The streams are catalytically cracked in thepresence of steam 272′ to produce crude olefin stream 408. Crude olefinstream 408 may include hydrocarbons having a carbon number of at least2. In some embodiments, crude olefin stream 408 contains at least 30% byweight C₂-C₅ olefins, at least 40% by weight C₂-C₅ olefins, at least 50%by weight C₂-C₅ olefins, at least 70% by weight C₂-C₅ olefins, or atleast 90% by weight C₂-C₅ olefins. Recycling the gasoline hydrocarbonsstream 400 into second catalytic cracking system 384 may provide for anadditional conversion across the overall process system of gas oilhydrocarbon stream 406 to C₂-C₅ olefins.

In some embodiments, second catalytic cracking system 384 includes anintermediate reaction zone and a stripping zone that are in fluidcommunication with each other, with the stripping zone located below theintermediate reaction zone. To provide for a high steam velocity withinthe stripping zone, as compared to the velocity within the intermediatereaction zone, the cross-sectional area of the stripping zone is lessthan the cross-sectional area of the intermediate reaction zone. Theratio of the stripping zone cross sectional area to the intermediatereaction zone cross sectional area may range from 0.1:1 to 0.9:1; from0.2:1 to 0.8:1; or from 0.3:1 to 0.7:1.

In some embodiments, the geometry of the second catalytic crackingsystem is such that it is generally cylindrical. The length-to-diameterratio of the stripping zone of the catalystic cracking system providesfor the desired high steam velocity within the stripping zone andprovides enough contact time within the stripping zone for the desiredstripping of the used regenerated catalyst that is to be removed fromthe second catalytic cracking system. Thus, the length-to-diameter ratioof the stripping zone may range of from 1:1 to 25:1; from 2:1 to 15:1;or from 3:1 to 10:1.

In some embodiments, second catalytic cracking system 384 is operated orcontrolled independently from the operation or control of catalyticcracking system 378. Independent operation or control of secondcatalytic cracking system 384 may improve overall conversion of thegasoline hydrocarbons into the desired products such as ethylene,propylene and butylenes. With independent operation of second catalyticcracking system 384, the severity of catalytic cracking unit 378 may bereduced to optimize the yield of C₂-C₅ olefins. A temperature in secondcatalytic cracking system 384 may range from about 482° C. (900° F.) toabout 871° C. (1600° F.), from about 510° C. (950° F.) to about 871° C.1600° F.), or from about 538° C. (1000° F.) to about 732° C. (1350° F.).The operating pressure of second catalytic cracking system 384 may rangefrom atmospheric to about 0.345 MPa (50 psig) or from about 0.034 to0.345 MPa (5 to 50 psig).

Addition of steam 272′ into second catalytic cracking system 384 mayassist in the operational control of the second catalytic cracking unit.In some embodiments, steam is not necessary. In some embodiments, theuse of the steam for a given gasoline hydrocarbon conversion across theprocess system, and in the cracking of the gasoline hydrocarbons, mayprovide for an improved selectivity toward C₂-C₅ olefin yield with anincrease in propylene and butylenes yield relative to other catalyticcracking processes. A weight ratio of steam to gasoline hydrocarbonsintroduced into second catalytic cracking system 384 may be up to orabout 15:1; from 0.1:1 to 10:1; from 0.2:1 to 9:1; or from 0.5:1to 8:1.

Crude olefin stream 408 enters olefin separation system 410. Olefinseparation system 410 can be any system known to those skilled in theart for recovering and separating the crude olefin stream 408 into C₂-C₅olefin product streams (for example, ethylene product stream 412,propylene product stream 414, and butylenes products stream 416). Olefinseparation system 410 may include such systems as absorbers andstrippers, fractionators, compressors and separators, or any combinationof known systems or equipment providing for the recovery and separationof C₂-C₅ olefin products from fluid stream 408. In some embodiments,olefin streams 412, 414, 416 enter alkylation unit 368 to generatehydrocarbon stream 370. In some embodiments, hydrocarbon stream 370 hasan octane number of at least 70, at least 80, or at least 90. In someembodiments, all or portions of one or more of streams 412, 414, 416 aretransported to other processing units, such as polymerization units, foruse as feedstocks.

In some embodiments, the crude product from the catalytic crackingsystem and the crude olefin stream from second catalytic cracking systemmay be combined. The combined stream may enter a single separation unit(for example, a combination of liquid separation system 398 and olefinseparation system 410).

In FIG. 11, used cracking catalyst stream 380 exits second catalyticcracking system 384 and enters catalytic cracking system 378. Catalystin used cracking catalyst stream 380 may include a slightly higherconcentration of carbon than the concentration of carbon that is on thecatalyst in regenerated cracking catalyst 382. A high concentration ofcarbon on the catalyst may partially deactivate the catalytic crackingcatalysts which provides for an enhanced yield of olefins from thecatalytic cracking system 378. Coke content of the used regeneratedcatalyst may be at least 0.1% by weight or at least 0.5% by weight. Thecoke content of the used regenerated catalyst may range from about 0.1%by weight to about 1% by weight or from about 0.1% by weight to about0.6% by weight.

The catalytic cracking catalyst used in catalytic cracking system 378and second catalytic cracking system 384 may be any fluidizable crackingcatalyst known in the art. The fluidizable cracking catalyst may includea molecular sieve having cracking activity dispersed in a porous,inorganic refractory oxide matrix or binder. “Molecular sieve” refers toany material capable of separating atoms or molecules based on theirrespective dimensions. Molecular sieves suitable for use as a componentof the cracking catalyst include pillared clays, delaminated clays, andcrystalline aluminosilicates. In some embodiments, the cracking catalystcontains a crystalline aluminosilicate. Examples of suchaluminosilicates include Y zeolites, ultrastable Y zeolites, X zeolites,zeolite beta, zeolite L, offretite, mordenite, faujasite, and zeoliteomega. In some embodiments, crystalline aluminosilicates for use in thecracking catalyst are X and/or Y zeolites. U.S. Pat. No. 3,130,007 toBreck describes Y-type zeolites.

The stability and/or acidity of a zeolite used as a component of thecracking catalyst may be increased by exchanging the zeolite withhydrogen ions, ammonium ions, polyvalent metal cations, such as rareearth-containing cations, magnesium cations or calcium cations, or acombination of hydrogen ions, ammonium ions and polyvalent metalcations. The sodium content may be lowered until it is at most 0.8% byweight, at most 0.5% by weight and at most 0.3% by weight, calculated asNa₂O. Methods of carrying out the ion exchange are well known in theart.

The zeolite or other molecular sieve component of the cracking catalystis combined with a porous, inorganic refractory oxide matrix, or binderto form a finished catalyst prior to use. The refractory oxide componentin the finished catalyst may be silica-alumina, silica, alumina, naturalor synthetic clays, pillared or delaminated clays, mixtures of one ormore of these components, and the like. In some embodiments, theinorganic refractory oxide matrix includes a mixture of silica-aluminaand a clay such as kaolin, hectorite, sepiolite, and attapulgite. Afinished catalyst may contain between about 5% by weight and about 40%by weight zeolite or other molecular sieve and greater than about 20weight percent inorganic refractory oxide. In some embodiments, thefinished catalyst may contain between about 10% and about 35% by weightzeolite or other molecular sieve, between about 10% and about 30% byweight inorganic refractory oxide, and between about 30% and about 70%by weight clay.

The crystalline aluminosilicate or other molecular sieve component ofthe cracking catalyst may be combined with the porous, inorganicrefractory oxide component or a precursor thereof by any suitabletechnique known in the art including mixing, mulling, blending orhomogenization. Examples of precursors that may be used include, but arenot limited to, alumina, alumina sols, silica sols, zirconia, aluminahydrogels, polyoxycations of aluminum and zirconium, and peptizedalumina. In some embodiments, the zeolite is combined with analumino-silicate gel or sol or other inorganic, refractory oxidecomponent, and the resultant mixture is spray dried to produce finishedcatalyst particles normally ranging in diameter between about 40micrometers and about 80 micrometers. In some embodiments, the zeoliteor other molecular sieve may be mulled or otherwise mixed with therefractory oxide component or precursor thereof, extruded and thenground into the desired particle size range. The finished catalyst mayhave an average bulk density between about 0.30 and about 0.90 gram percubic centimeter and a pore volume between about 0.10 and about 0.90cubic centimeter per gram.

In some embodiments, a ZSM-5 additive may be introduced into theintermediate cracking reactor of second catalytic cracking system 384.When a ZSM-5 additive is used along with the selected cracking catalystin the intermediate cracking reactor, a yield of the lower olefins suchas propylene and butylenes is enhanced. An amount of ZSM-5 ranges fromat most 30% by weight, at most 20% by weight, or at most 18% by weightof the regenerated catalyst being introduced into second catalyticcracking system 384. An amount of ZSM-5 additive is introduced intosecond catalytic cracking system 384 may range from 1% to 30% by weight,3% to 20% by weight, or 5% to 18% by weight of the regenerated crackingcatalyst being introduced into second catalytic cracking system 384.

The ZSM-5 additive is a molecular sieve additive selected from thefamily of medium pore size crystalline aluminosilicates or zeolites.Molecular sieves that can be used as the ZSM-5 additive include, but arenot limited to, medium pore zeolites as described in “Atlas of ZeoliteStructure Types,” Eds. W. H. Meier and D. H. Olson,Butterworth-Heineman, Third Edition, 1992. The medium pore size zeolitesgenerally have a pore size from about 0.5 nm, to about 0.7 nm andinclude, for example, MEI, MFS, MEL, MTW, EUO, MTT, HEU, FER, and TONstructure type zeolites (IUPAC Commission of Zeolite Nomenclature).Non-limiting examples of such medium pore size zeolites, includingZSM-5, ZSM-12, ZSM-22, ZSM-23, ZSM-34, ZSM-35, ZSM-38, ZSM-48, ZSM-50,silicalite, and silicalite 2. ZSM-5, are described in U.S. Pat. No.3,702,886 to Argauer Ct al. and U.S. Pat No. 3,770,614 to Graven, bothof which are incorporated by reference herein.

ZSM-11 is described in U.S. Pat. No. 3,709,979 to Chu; ZSM-12 in U.S.Pat. No. 3,832,449 to Rosinski et al.; ZSM-21 and ZSM-38 in U.S. Pat.No. 3,948,758 to Bonacci et al.; ZSM-23 in U.S. Pat. No. 4,076,842 toPlank et al.; and ZSM-35 in U.S. Pat. No. 4,016,245 to Plank et al., allof which are incorporated by reference herein. Other suitable molecularsieves include the silicoalumninophosphates (SAPO), such as SAPO-4 andSAPO-11 which is described in U.S. Pat. No. 4,440,871 to Lok et al.;chromosilicates; gallium silicates, iron silicates; aluminum phosphates(ALPO), such as ALPO-11 described in U.S. Pat. No. 4,310,440 to Wilsonet al.; titanium aluminosilicates (TASO), such as TASO-45 described inU.S. Pat. No. 4,686,029 to Pellet et al.; boron silicates, described inU.S. Pat. No. 4,254,297 Frenken et al.; titanium aluminophosphates(TAPO), such as TAPO-11 described in U.S. Pat. No. 4,500,651 to Lok etal.; and iron aluminosilicates, all of which are incorporated byreference herein.

U.S. Pat. No. 4,368,114 to Chester et al., which is incorporated byreference herein, describes in detail the class of zeolites that can besuitable ZSM-5 additives. The ZSM-5 additive may be held together with acatalytically inactive inorganic oxide matrix component, in accordancewith conventional methods.

In some embodiments, residue produced from units described in FIGS. 10and 11 may be used as an energy source. The residue may be gasified toproduce gases which are burned (for example, burned in a turbine) and/orinjected into a subsurface formation (for example, injection of producedcarbon dioxide into a subsurface formation). In certain embodiments, theresidue is de-asphalted to produce asphalt. The asphalt may be gasified.

During some in situ heat treatment processes, ammonia may be information fluid produced from the formation. Produced ammonia may beused for a number of purposes. In some embodiments, the ammonia or aportion of the ammonia may be used to produce hydrogen. In someembodiments, the Haber-Bosch process may be used to produce hydrogen.Ammonia may produce hydrogen and nitrogen according to the followingequilibrium reaction:N₂+3H₂

2NH₃  (1)

The reaction may be a high temperature, high pressure, catalyzedreaction. The temperature may be from about 300° C. to about 800° C. Thepressure may be from about 80 bars to about 220 bars. The catalyst maybe composed substantially of iron. The total amount of hydrogen producedmay be increased by shifting the equilibrium towards hydrogen andnitrogen production. Equilibrium may be shifted to produce more nitrogenand hydrogen by removing nitrogen and/or hydrogen as they are produced.

Many wells are needed for treating a hydrocarbon formation using an insitu heat treatment process. In some embodiments, vertical orsubstantially vertical wells are formed in the formation. In someembodiments, horizontal or U-shaped wells are formed in the formation.In some embodiments, combinations of horizontal and vertical wells areformed in the formation. Wells may be formed using drilling rigs.

In an embodiment, a rig for drilling wells includes equipment on the rigfor drilling multiple wellbores simultaneously. The rig may include oneor more systems for constructing the wells, including drilling, fluidhandling, and cementing of the wells through the overburden, drilling tototal depth, and placing completion equipment such as heaters andcasing. The rig may be particularly useful for forming closely spacedwells, such as freeze wells.

In some embodiments, a rig for drilling wellbores for an in situ heattreatment process may be a movable platform. The working surface of theplatform may be 20 m or more above the ground. Piping may be suspendedfrom the bottom of the platform before being deployed.

In some embodiments, wells are drilled in sequential stages withdifferent drilling machines. The wells may be barrier wells, heaterwells, production wells, production/heater wells, monitor wells,injection wells, or other types of wells. A conductor drilling machinemay set the conductor of the well. A main hole drilling machine maydrill the wellbore to depth. A completion drilling machine may placecasing, cement, tubing, cables, heaters, and perform other wellcompletion tasks. The drilling machines may be on the same locationmoving 3 to 10 meters between wells for 2 to 3 years. The size and theshape of the drilling machines may not have to meet existing roadtransportation regulations since once in the field, the drillingmachines may remain there for the duration of the project. The majorcomponents of the drilling machines may be transported to location andassembled there. The drilling machines may not have to be disassembledfor a multi-mile move for several years.

One or more central plants may support the drilling machines. The use ofa central plant may allow for smaller drilling machines. The centralplant may include prime movers, mud tanks, solids handling equipment,pipe handling, power, and other equipment common to the drillingmachines. The equipment of the central plant may be coupled to thedrilling machines by flexible umbilicals, by easily modifiable piping,and/or by quick release electrical connections. Several wells may bedrilled before the need to move the central plant arises. In someembodiments, the central plant may be moved while connected to one ormore operating drilling machines. The drilling machines and centralplant may be designed with integrated drip pans to capture leaks andspills.

In some embodiments, the drilling machines are powered directly off theelectric grid. In other embodiments, the drilling machines are dieselpowered. Using diesel power may avoid complications associated withinterfering with the installation of electrical and other systems neededfor the wells of the in situ heat treatment process.

The drilling machines may be automated so that little or no humaninteraction is required. The tubulars used by the drilling machines maybe stacked and stored on or by the drilling machines so that thedrilling machines can access and manipulate the tubulars with minimal orno human intervention. For example, a carousel or other device may beused to store a tubular and move the tubular from storage to thedrilling mast. The carousel or other device may also be used to move thetubular from the drilling mast to storage.

The drilling machines may include propulsion units so that the drillingmachines do not need to be skidded. The central plant may also includepropulsion units. Skidding involves extra equipment not used fordrilling the wells and may be complicated by the dense concentration ofsurface facilities and equipment. In some embodiments, the drillingmachines and/or central plant may include tracks or a walking mechanismto eliminate railroad-type tracks. Eliminating railroad-type tracks mayreduce the amount of pre-work road and rail formation that needs to becompleted before drilling operations can begin. In some embodiments, thepropulsion units may include a fixed-movement mechanism. Thefixed-movement mechanism may advance the drilling machine a set distancewhen activated so that the drilling machine is located at the next welllocation. Fine adjustment may allow for exact positioning of thedrilling machine after initial position location by the fixed-movementmechanism. In some embodiments, laser guidance systems may be utilizedto position the drilling machines. The laser guidance systems may ensurethat the wellbores being formed are started at the right location in thewell pattern. In some embodiments, drilling machines and/or the centralplant are positioned on a central track or access lane. The drillingequipment may be extended from one side to the other of the centraltrack to form the wells. The drilling machine is able to stay in oneplace while an arm or cantilever mechanism allows multiples of wells tobe drilled around the drilling machine. The wells may be drilled in veryclose proximity if required.

The drilling machines and the central plant may be self-leveling andable to function on up to a 10% grade or higher. In some embodiments,the drilling machines include hydraulic and/or mechanical levelingsystems. The drilling machines and central plant may have groundclearances of at least 1 meter so that the units may be movedunobstructed over wellheads. Each drilling machine may include amechanism for precisely placing the working components of the drillingmachine over the hole center of the well being formed. In someembodiments, the mechanism adjusts the position of a derrick of thedrilling machine.

The drilling machines may be moved from one well to another withderricks of the drilling machines in upright or inclined positions. Theterm “derrick” is used to represent whatever top drive support device isemployed on the rig, whether the top drive support device is a derrick,stiff mast, or hydraulic arm. Because some drilling machines may usethree 10 m pipe sections, the derrick may have to be lowered for rigmoves. If the derrick must be lowered, lowering and raising the derrickneeds to be a quick and safe operation. In some embodiments, the derrickis lowered with the bottom hole assembly racked in the derrick to savetime handling the bottom hole assembly. In other embodiments, the bottomhole assembly is separated from the derrick for servicing during a moveof the drilling machine.

In some embodiments, one of the drilling machines is able to do morethan one stage of well formation. In some embodiments, a freeze wall orother barrier is formed around all or a portion of a treatment area.There may be about a year or more of time from when the last freeze wellis drilled to the time that main holes for heater and producer wells canbe drilled. In the intervening time, the drilling machine used to drillthe main hole of a well may be used to preset conductors for heaterwells and/or production wells in the treatment area.

In some embodiments, two or more drilling machines are placed on thesame carrier. For example, the carrier may include equipment thatpresets the conductor for a well. The carrier may also carry equipmentfor forming the main hole. One portion of the machine could bepresetting a conductor while another portion of the machine could besimultaneously forming the main hole of a second well.

Running drill pipe to replace bits, running in down hole equipment andpulling the equipment out after use may be time consuming and expensive.To save time and expense, all drilling and completion tools may go intothe hole and not come out. For example, drill pipe may become casing.Once data is obtained from logging runs, the logging tools are left inthe hole and drilling proceeds through them or past them if necessary.Downhole equipment is integrated into the drill pipe. In someembodiments, the drill pipe becomes a conduit of a conduit-in-conduitheater.

In some embodiments, a retractable drilling assembly is used. Using aretractable drilling assembly may be beneficial when using continuouscoiled tubing. When total depth of the well is reached, the drill bitand bottom hole assembly may be retracted to a smaller diameter. Thedrill bit and bottom hole assembly may be brought to the surface throughthe coiled tubing. The coiled tubing may be left in the hole as casing.

In some embodiments, the main hole drilling machine and the completiondrilling machine include a quick-connect device for attaching the fluiddiverter spool (drilling wellhead) to the conductor casing. The use of aquick-connect device may be faster than threading or welding thediverter to the conductor casing. The quick-connect device may be asnap-on or clamp-on type diverter. Wellheads are typically designed tofit a multitude of casing configurations, everything from 48 inchconductor to 2⅜ inch tubing. For an in situ heat treatment process, thewellheads may not need to span such a large casing diameter set or havemultiple string requirements. The wellheads may only handle a verylimited pipe diameter range and only one or two casing strings. Having afit for purpose wellhead may significantly reduce the cost offabricating and installing the wellheads for the wells of the in situheat treatment process.

In some embodiments, the main hole drilling machine includes aslickline/boom system. The slickline/boom system may allow runningranging equipment in a close offset well while drilling the well thedrilling machine is positioned over. The use of the slickline/boomsystem on the drilling machine may eliminate the need for additionalequipment for employing the ranging equipment.

In some embodiments, the conductor drilling machine is a blast-hole rig.The blast-hole rig may be mounted on a crawler or carrier with metaltracks. Air or gas compression is on board the blast-hole rig. Tubularsmay be racked horizontally on the blast-hole rig. The derrick of theblast-hole rig may be adjusted to hole center. The bottom hole drillingassembly of the blast-hole rig may be left in the derrick when theblast-hole rig is moved. In some embodiments, the blast-hole rigincludes an integral drilling fluid tank, solids control equipment, anda mist collector. In some embodiments, the drilling fluid tank, thesolids control equipment, and/or the mist collector is part of thecentral plant.

During well formation with jointed pipe, one time consuming task ismaking connections. To reduce the number of connections needed duringformation of wells, long lengths of pipe may be used. In someembodiments, the drilling machines are able to use pipe with a length ofabout 25 m to 30 m. The 25 m to 30 m piping may be made up of two ormore shorter joints, but is preferably a single joint of the appropriatelength. Using a single joint may decrease the complexity of pipehandling and result in fewer potential leak paths in the drill string.In some embodiments, the drilling machines use jointed pipe having otherlengths, such as 20 m lengths, or 10 m lengths.

The drilling machine may use a top drive system. In some embodiments,the top drive system functions using a rack and pinion. In someembodiments, the top drive system functions using a hydraulic system.

The drilling machines may include automated pipe handling systems. Theautomated pipe handling system may be able to lift pipe, makeconnections, and have another joint in the raised position ready for thenext connection. The automated pipe handling systems may include an ironroughneck to make and break connections. In some embodiments, the pipeskid for the drilling machine is an integral component of the drillingmachine.

String floats (check valves) may be needed in the drill string becauseair and/or liquid will be used during drilling. An integral float valvemay be positioned in each joint used by the drilling machine. Includinga string float in each joint may minimize circulating times atconnections and speed up the connection process.

Drilling the wells may be done at low operating pressures. In someembodiments, a quick-connect coupler is used to connect drill pipetogether because of the low operating pressures. Using quick-connectcouplers to join drill pipe may reduce drilling time and simplify pipehandling automation.

In certain embodiments, the main hole drilling machine is designed todrill 6¼ inch or 6½ inch holes. The pumping capabilities needed tosupport the main hole drilling machine may include 3×900 scfin aircompressors, a 2000 psi booster, and a liquid pump with an operationalmaximum of 325 gpm. A 35 gpm pump may also be included if mist drillingis required.

In some embodiments, the main hole drilling machine and/or thecompletion drilling machine uses coiled tubing. Coiled tubing may allowfor minimal or no pipe connections above the bottom hole assembly.However, the drilling machine still needs the ability to deploy andretrieve the individual components of the bottom hole assembly. In someembodiments, components are automatically retrieved by a carousel,deployed, and made up over the hole when running in the hole. Theprocess may be reversed when tripping out of the hole. Alternatively,components may be racked horizontally on the drilling machine. Thecomponents may be maneuvered with automatic pipe arms.

The drilling machine may employ a split injector system. When coiledtubing operations are halted, the two sides of the injector may beremotely unlatched and retracted to allow for over hole access.

In some embodiments that use coiled tubing, a bottom hole assemblyhandling rig is used to make up and deploy the bottom hole assembly inthe well conductor of a well to be drilled to total depth. The drillingmachine may leave the current bottom hole assembly in the well afterreaching total depth and prior to moving to the next well. Afterlatching on to the bottom hole assembly in the follow up well, thebottom hole assembly handling rig may pull the bottom hole assembly fromthe previous well and prepare it for the next well in sequence. The mastfor the bottom hole assembly handling rig may be a very simplearrangement supporting a sandline for bottom hole assembly handling. Insome embodiments, the wellbore in which the coiled tubing is placed isformed by jet drilling.

In some embodiments, coiled tubing may be carbon steel. Carbon steelcoiled tubing may be used for only a limited number of cycles becausecoiling and/or uncoiling the steel forces the coiled tubing past theelastic region of the stress/strain curve and into the plastic region.In the plastic region, the steel is permanently deformed and/orweakened. For some coiled tubing uses, the coiled tubing is placed inthe formation and left in the formation, so the use of carbon steelcoiled tubing does not present a problem. For some coiled tubing uses,the coiled tubing may be coiled and uncoiled many times. For coiledtubing that needs to be coiled and uncoiled many times, the coiledtubing may be composite coiled tubing. Composite coiled tubing may stayin the elastic region during coiling and uncoiling so that there islittle or no permanent deformation of the coiled tubing duringdeployment and retrieval. Composite coiled tubing is available fromFiberspar LinePipe LLC (Houston, Tex., U.S.A.). In some embodiments,composite coiled tubing may include one or more electrical wires in thecomposite. The electrical wires may be coupled to equipment and loweredinto the wellbore with the coiled tubing.

Coiled tubing may be stored on a reel before deployment. A reel used bythe drilling machine may have 500-1000 m of pipe. To increase the numberof cycles the coiled tubing may be used, the reel may have a largediameter and be relatively narrow. In some embodiments, the coiledtubing reel is the wellhead. Having the wellhead and the reel as oneunit eliminates the additional handling of a separate wellhead and anempty reel.

Reverse circulation drilling enables fast penetration rates and the useof low density drilling fluid such as air or mist. When tri-cone rockbits are used, a skirted rock bit assembly replaces the conventionaltri-cone bit. The skirt directs the drilling fluid from the pipe-in-pipedrill rod annulus to the outside portion of the hole being drilled. Asthe cuttings are generated by the action of the rotating drill bit, thecuttings mix with the drilling fluid, pass through a hole in the centerof the bit and are carried out of the hole through the center of thedrill rods. When a non-skirted drill bit is used, a reverse-circulationcrossover is installed between the standard bit and the drill rods. Thecrossover redirects the drilling fluid from the pipe-in-pipe drill rodannulus to the inside of the drill string about a meter above the bit.The drilling fluid passes through the bit jets, mixes with the cuttings,and returns up the drill string. At the crossover, the fluid/cuttingsmixture enters the drill string and continues to the surface inside theinner tube of the drill rod.

FIG. 12 depicts a schematic drawing of a reverse-circulatingpolycrystalline diamond compact drill bit design. Thereverse-circulating polycrystalline diamond compact (RC-PDC) drill bitdesign eliminates the crossover. RC-PDC bit 418 may include skirt 420that directs the drilling fluid from pipe-in-pipe drill rod annulus 422to bottom portion 42 of the wellbore being formed. In bottom portion424, the drilling fluid mixes with the cuttings generated by cutters 426of the RC-PDC bit. The drilling fluid and cuttings pass through opening428 in the center of RC-PDC bit 418 and are carried out of the wellborethrough drill rod center 430.

In some embodiments, the cuttings generated during drilling are milledand used as a filler material in a slurry used for forming a grout wall.Cuttings that contain hydrocarbon material may be retorted to extractthe hydrocarbons. Retorting the cuttings may be environmentallybeneficial because the reinjected cuttings are free of organic material.Recovering the hydrocarbons may offset a portion of the milling cost.

FIG. 13 depicts a schematic drawing of a drilling system. Pilot bit 432may form an opening in the formation. Pilot bit 432 may be followed byfinal diameter bit 434. In some embodiments, pilot bit 432 may be about2.5 cm in diameter. Pilot bit 432 may be one or more meters below finaldiameter bit 434. Pilot bit 432 may rotate in a first direction andfinal diameter bit 434 may rotate in the opposite direction.Counter-rotating bits may allow for the formation of the wellbore alonga desired path. Standard mud may be used in both pilot bit 432 and finaldiameter bit 434. In some embodiments, air or mist may be used as thedrilling fluid in one or both bits.

During some in situ heat treatment processes, wellbores may need to beformed in heated formations. Wellbores drilled into hot formation may beadditional or replacement heater wells, additional or replacementproduction wells and/or monitor wells. In some in situ heat treatmentprocesses, a barrier formed around all or a portion of the in situ heattreatment process is formed by freeze wells that form a low temperaturezone around the freeze wells. A portion of the cooling capacity of thefreeze well equipment may be utilized to cool the equipment needed todrill into the hot formation. Drilling bits may be advanced slowly inhot sections to ensure that the formed wellbore cools sufficiently topreclude drilling problems.

FIG. 14 depicts a schematic drawing of a system for drilling into a hotformation. Cold mud is introduced to drilling bit 434 through conduit436. As the bit penetrates into the formation, the mud cools the bit andthe surrounding formation. In an embodiment, a pilot hole is formedfirst and the wellbore is finished with a larger drill bit later. In anembodiment, the finished wellbore is formed without a pilot hole beingformed. Well advancement is very slow to ensure sufficient cooling.

FIG. 15 depicts a schematic drawing of a system for drilling into a hotformation. Mud is introduced through conduit 436. Closed loop system 438is used to circulate cooling fluid. The cooling fluid cools the drillingmud and the formation as drilling bit 434 slowly penetrates into theformation.

FIG. 16 depicts a schematic drawing of a system for drilling into a hotformation. Mud is introduced through conduit 436. Pilot bit 432 isfollowed by final diameter bit 434. Closed loop system 438 is used tocirculate cooling fluid. The cooling fluid cools the drilling mudsupplied to the drill bits. The cooled drilling mud cools the formation.

In some embodiments, one or more portions of a wellbore may need to beisolated from other portions of the wellbore to establish zonalisolation. In some embodiments, an expandable may be positioned in thewellbore adjacent to a section of the wellbore that is to be isolated. Apig or hydraulic pressure may be used to enlarge the expandable toestablish zonal isolation.

In some embodiments, pathways may be formed in the formation after thewellbores are formed. Pathways may be formed adjacent to heaterwellbores and/or adjacent to production wellbores. The pathways maypromote better fluid flow and/or better heat conduction. In someembodiments, pathways are formed by hydraulically fracturing theformation. Other fracturing techniques may also be used. In someembodiments, small diameter bores may be formed in the formation. Insome embodiments, heating the formation may expand and close orsubstantially close the fractures or bores formed in the formation toenhance heat conduction.

Some wellbores formed in the formation may be used to facilitateformation of a perimeter barrier around a treatment area. Heat sourcesin the treatment area may heat hydrocarbons in the formation within thetreatment area. The perimeter barrier may be, but is not limited to, alow temperature or frozen barrier formed by freeze wells, dewateringwells, a grout wall formed in the formation, a sulfur cement barrier, abarrier formed by a gel produced in the formation, a barrier formed byprecipitation of salts in the formation, a barrier formed by apolymerization reaction in the formation, and/or sheets driven into theformation. Heat sources, production wells, injection wells, dewateringwells, and/or monitoring wells may be installed in the treatment areadefine by the barrier prior to, simultaneously with, or afterinstallation of the barrier.

A low temperature zone around at least a portion of a treatment area maybe formed by freeze wells. In an embodiment, refrigerant is circulatedthrough freeze wells to form low temperature zones around each freezewell. The freeze wells are placed in the formation so that the lowtemperature zones overlap and form a low temperature zone around thetreatment area. The low temperature zone established by freeze wells ismaintained below the freezing temperature of aqueous fluid in theformation. Aqueous fluid entering the low temperature zone freezes andforms the frozen barrier. In other embodiments, the freeze barrier isformed by batch operated freeze wells. A cold fluid, such as liquidnitrogen, is introduced into the freeze wells to form low temperaturezones around the freeze wells. The fluid is replenished as needed.

In some embodiments, two or more rows of freeze wells are located aboutall or a portion of the perimeter of the treatment area to form a thickinterconnected low temperature zone. Thick low temperature zones may beformed adjacent to areas in the formation where there is a high flowrate of aqueous fluid in the formation. The thick barrier may ensurethat breakthrough of the frozen barrier established by the freeze wellsdoes not occur.

In some embodiments, a double barrier system is used to isolate atreatment area. The double barrier system may be formed with a firstbarrier and a second barrier. The first barrier may be formed around atleast a portion of the treatment area to inhibit fluid from entering orexiting the treatment area. The second barrier may be formed around atleast a portion of the first barrier to isolate an inter-barrier zonebetween the first barrier and the second barrier. The inter-barrier zonemay have a thickness from about 1 m to about 300 m. In some embodiments,the thickness of the inter-barrier zone is from about 10 m to about 100m, or from about 20 m to about 50 m.

The double barrier system may allow greater project depths than a singlebarrier system. Greater depths are possible with the double barriersystem because the stepped differential pressures across the firstbarrier and the second barrier is less than the differential pressureacross a single barrier. The smaller differential pressures across thefirst barrier and the second barrier make a breach of the double barriersystem less likely to occur at depth for the double barrier system ascompared to the single barrier system.

The double barrier system reduces the probability that a barrier breachwill affect the treatment area or the formation on the outside of thedouble barrier. That is, the probability that the location and/or timeof occurrence of the breach in the first barrier will coincide with thelocation and/or time of occurrence of the breach in the second barrieris low, especially if the distance between the first barrier and thesecond barrier is relatively large (for example, greater than about 15m). Having a double barrier may reduce or eliminate influx of fluid intothe treatment area following a breach of the first barrier or the secondbarrier. The treatment area may not be affected if the second barrierbreaches. If the first barrier breaches, only a portion of the fluid inthe inter-barrier zone is able to enter the contained zone. Also, fluidfrom the contained zone will not pass the second barrier. Recovery froma breach of a barrier of the double barrier system may require less timeand fewer resources than recovery from a breach of a single barriersystem. For example, reheating a treatment area zone following a breachof a double barrier system may require less energy than reheating asimilarly sized treatment area zone following a breach of a singlebarrier system.

The first barrier and the second barrier may be the same type of barrieror different types of barriers. In some embodiments, the first barrierand the second barrier are formed by freeze wells. In some embodiments,the first barrier is formed by freeze wells, and the second barrier is agrout wall. The grout wall may be formed of cement, sulfur, sulfurcement, or combinations thereof. In some embodiments, a portion of thefirst barrier and/or a portion of the second barrier is a naturalbarrier, such as an impermeable rock formation.

Vertically positioned freeze wells and/or horizontally positioned freezewells may be positioned around sides of the treatment area. If the upperlayer (the overburden) or the lower layer (the underburden) of theformation is likely to allow fluid flow into the treatment area or outof the treatment area, horizontally positioned freeze wells may be usedto form an upper and/or a lower barrier for the treatment area. In someembodiments, an upper barrier and/or a lower barrier may not benecessary if the upper layer and/or the lower layer are at leastsubstantially impermeable. If the upper freeze barrier is formed,portions of heat sources, production wells, injection wells, and/ordewatering wells that pass through the low temperature zone created bythe freeze wells forming the upper freeze barrier wells may be insulatedand/or heat traced so that the low temperature zone does not adverselyaffect the functioning of the heat sources, production wells, injectionwells and/or dewatering wells passing through the low temperature zone.

Spacing between adjacent freeze wells may be a function of a number ofdifferent factors. The factors may include, but are not limited to,physical properties of formation material, type of refrigeration system,coldness and thermal properties of the refrigerant, flow rate ofmaterial into or out of the treatment area, time for forming the lowtemperature zone, and economic considerations. Consolidated or partiallyconsolidated formation material may allow for a large separationdistance between freeze wells. A separation distance between freezewells in consolidated or partially consolidated formation material maybe from about 3 m to about 20 m, about 4 m to about 15 m, or about 5 mto about 10 m. In an embodiment, the spacing between adjacent freezewells is about 5 m. Spacing between freeze wells in unconsolidated orsubstantially unconsolidated formation material, such as in tar sand,may need to be smaller than spacing in consolidated formation material.A separation distance between freeze wells in unconsolidated materialmay be from about 1 m to about 5 m.

Freeze wells may be placed in the formation so that there is minimaldeviation in orientation of one freeze well relative to an adjacentfreeze well. Excessive deviation may create a large separation distancebetween adjacent freeze wells that may not permit formation of aninterconnected low temperature zone between the adjacent freeze wells.Factors that influence the manner in which freeze wells are insertedinto the ground include, but are not limited to, freeze well insertiontime, depth that the freeze wells are to be inserted, formationproperties, desired well orientation, and economics.

Relatively low depth wellbores for freeze wells may be impacted and/orvibrationally inserted into some formations. Wellbores for freeze wellsmay be impacted and/or vibrationally inserted into formations to depthsfrom about 1 m to about 100 m without excessive deviation in orientationof freeze wells relative to adjacent freeze wells in some types offormations.

Wellbores for freeze wells placed deep in the formation, or wellboresfor freeze wells placed in formations with layers that are difficult toimpact or vibrate a well through, may be placed in the formation bydirectional drilling and/or geosteering. Acoustic signals, electricalsignals, magnetic signals, and/or other signals produced in a firstwellbore may be used to guide directionally drilling of adjacentwellbores so that desired spacing between adjacent wells is maintained.Tight control of the spacing between wellbores for freeze wells is animportant factor in minimizing the time for completion of barrierformation.

In some embodiments, one or more portions of freeze wells may be angledin the formation. The freeze wells may be angled in the formationadjacent to aquifers. In some embodiments, the angled portions areangled outwards from the treatment area. In some embodiments, the angledportions may be angled inwards towards the treatment area. The angledportions of the freeze wells allow extra length of freeze well to bepositioned in the aquifer zones. Also, the angled portions of the freezewells may reduce the shear load applied to the frozen barrier by waterflowing in the aquifer.

After formation of the wellbore for the freeze well, the wellbore may bebackflushed with water adjacent to the part of the formation that is tobe reduced in temperature to form a portion of the freeze barrier. Thewater may displace drilling fluid remaining in the wellbore. The watermay displace indigenous gas in cavities adjacent to the formation. Insome embodiments, the wellbore is filled with water from a conduit up tothe level of the overburden. In some embodiments, the wellbore isbackflushed with water in sections. The wellbore maybe treated insections having lengths of about 6 m, 10 m, 14 m, 17 m, or greater.Pressure of the water in the wellbore is maintained below the fracturepressure of the formation. In some embodiments, the water, or a portionof the water is removed from the wellbore, and a freeze well is placedin the formation.

FIG. 17 depicts an embodiment of freeze well 440. Freeze well 440 mayinclude canister 442, inlet conduit 444, spacers 446, and wellcap 448.Spacers 446 may position inlet conduit 444 in canister 442 so that an anis formed between the canister and the conduit. Spacers 446 may promoteturbulent flow of refrigerant in the annular space between inlet conduit444 and canister 442, but the spacers may also cause a significant fluidpressure drop. Turbulent fluid flow in the annular space may be promotedby roughening the inner surface of canister 442, by roughening the outersurface of inlet conduit 444, and/or by having a small cross-sectionalarea annular space that allows for high refrigerant velocity in theannular space. In some embodiments, spacers are not used. Wellhead 450may suspend canister 442 in wellbore 452.

Formation refrigerant may flow through cold side conduit 454 from arefrigeration unit to inlet conduit 444 of freeze well 440. Theformation refrigerant may flow through an annular space between inletconduit 444 and canister 442 to warm side conduit 456. Heat may transferfrom the formation to canister 442 and from the canister to theformation refrigerant in the annular space. Inlet conduit 444 may beinsulated to inhibit heat transfer to the formation refrigerant duringpassage of the formation refrigerant into freeze well 440. In anembodiment, inlet conduit 444 is a high density polyethylene tube. Atcold temperatures, some polymers may exhibit a large amount of thermalcontraction. For example, a 260 m initial length of polyethylene conduitsubjected to a temperature of about −25° C. may contract by 6 m or more.If a high density polyethylene conduit, or other polymer conduit, isused, the large thermal contraction of the material must be taken intoaccount in determining the final depth of the freeze well. For example,the freeze well may be drilled deeper than needed, and the conduit maybe allowed to shrink back during use. In some embodiments, inlet conduit444 is an insulated metal tube. In some embodiments, the insulation maybe a polymer coating, such as, but not limited to, polyvinylchloride,high density polyethylene, and/or polystyrene.

Freeze well 440 may be introduced into the formation using a coiledtubing rig. In an embodiment, canister 442 and inlet conduit 444 arewound on a single reel. The coiled tubing rig introduces the canisterand inlet conduit 444 into the formation. In an embodiment, canister 442is wound on a first reel and inlet conduit 444 is wound on a secondreel. The coiled tubing rig introduces canister 442 into the formation.Then, the coiled tubing rig is used to introduce inlet conduit 444 intothe canister. In other embodiments, freeze well is assembled in sectionsat the wellbore site and introduced into the formation.

An insulated section of freeze well 440 may be placed adjacent tooverburden 458. An uninsulated section of freeze well 440 may be placedadjacent to layer or layers 460 where a low temperature zone is to beformed. In some embodiments, uninsulated sections of the freeze wellsmay be positioned adjacent only to aquifers or other permeable portionsof the formation that would allow fluid to flow into or out of thetreatment area. Portions of the formation where uninsulated sections ofthe freeze wells are to be placed may be determined using analysis ofcores and/or logging techniques.

Various types of refrigeration systems may be used to form a lowtemperature zone. Determination of an appropriate refrigeration systemmay be based on many factors, including, but not limited to: a type offreeze well; a distance between adjacent freeze wells; a refrigerant; atime frame in which to form a low temperature zone; a depth of the lowtemperature zone; a temperature differential to which the refrigerantwill be subjected; one or more chemical and/or physical properties ofthe refrigerant; one or more environmental concerns related to potentialrefrigerant releases, leaks or spills; one or more economic factors;water flow rate in the formation; composition and/or properties offormation water including the salinity of the formation water; and oneor more properties of the formation such as thermal conductivity,thermal difflisivity, and heat capacity.

A circulated fluid refrigeration system may utilize a liquid refrigerant(formation refrigerant) that is circulated through freeze wells. Some ofthe desired properties for the formation refrigerant are: low workingtemperature, low viscosity at and near the working temperature, highdensity, high specific heat capacity, high thermal conductivity, lowcost, low corrosiveness, and low toxicity. A low working temperature ofthe formation refrigerant allows a large low temperature zone to beestablished around a freeze well. The low working temperature offormation refrigerant should be about −20° C. or lower. Formationrefrigerants having low working temperatures of at least −60° C. mayinclude aqua ammonia, potassium formate solutions such as Dynalene®HC-50 (Dynalene® Heat Transfer Fluids (Whitehall, Pa., U.S.A.)) orFREEZIUM® (Kemira Chemicals (Helsinki, Finland)); silicone heat transferfluids such as Syltherm XLT® (Dow Corning Corporation (Midland, Mich.,U.S.A.); hydrocarbon refrigerants such as propylene; andchlorofluorocarbons such as R-22. Aqua ammonia is a solution of ammoniaand water with a weight percent of ammonia between about 20% and about40%. Aqua ammonia has several properties and characteristics that makeuse of aqua ammonia as the formation refrigerant desirable. Suchproperties and characteristics include, but are not limited to, a verylow freezing point, a low viscosity, ready availability, and low cost.

Formation refrigerant that is capable of being chilled below a freezingtemperature of aqueous formation fluid may be used to form the lowtemperature zone around the treatment area. The following equation (theSanger equation) may be used to model the time t₁ needed to form afrozen barrier of radius R around a freeze well having a surfacetemperature of T_(s):

$\begin{matrix}{{t_{1} = {\frac{R^{2}L_{1}}{4k_{f}v_{s}}\left( {{2\ln\frac{R}{r_{o}}} - 1 + \frac{c_{vf}v_{s}}{L_{1}}} \right)}}{{in}\mspace{14mu}{which}\text{:}}\begin{matrix}{L_{1} = {L\frac{a_{r}^{2} - 1}{2\;\ln\mspace{11mu} a_{r}}c_{vu}v_{o}}} \\{a_{r} = {\frac{R_{A}}{R}.}}\end{matrix}} & (2)\end{matrix}$In these equations, k_(f) is the thermal conductivity of the frozenmaterial; c_(vf) and c_(vu) are the volumetric heat capacity of thefrozen and unfrozen material, respectively; r_(o) is the radius of thefreeze well; v_(s) is the temperature difference between the freeze wellsurface temperature T_(s) and the freezing point of water T_(o); v_(o)is the temperature difference between the ambient ground temperatureT_(g) and the freezing point of water T_(o); L is the volumetric latentheat of freezing of the formation; R is the radius at thefrozen-unfrozen interface; and R_(A) is a radius at which there is noinfluence from the refrigeration pipe. The Sanger equation may provide aconservative estimate of the time needed to form a frozen barrier ofradius R because the equation does not take into considerationsuperposition of cooling from other freeze wells. The temperature of theformation refrigerant is an adjustable variable that may significantlyaffect the spacing between freeze wells.

EQN. 2 implies that a large low temperature zone may be formed by usinga refrigerant having an initial temperature that is very low. The use offormation refrigerant having an initial cold temperature of about −30°C. or lower is desirable. Formation refrigerants having initialtemperatures warmer than about −30° C. may also be used, but suchformation refrigerants require longer times for the low temperaturezones produced by individual freeze wells to connect. In addition, suchformation refrigerants may require the use of closer freeze wellspacings and/or more freeze wells.

The physical properties of the material used to construct the freezewells may be a factor in the determination of the coldest temperature ofthe formation refrigerant used to form the low temperature zone aroundthe treatment area. Carbon steel may be used as a construction materialof freeze wells. ASTM A333 grade 6 steel alloys and ASTM A333 grade 3steel alloys may be used for low temperature applications. ASTM A333grade 6 steel alloys typically contain little or no nickel and have alow working temperature limit of about −50° C. ASTM A333 grade 3 steelalloys typically contain nickel and have a much colder low workingtemperature limit. The nickel in the ASTM A333 grade 3 alloy addsductility at cold temperatures, but also significantly raises the costof the metal. In some embodiments, the coldest temperature of therefrigerant is from about −35° C. to about −55° C., from about −38° C.to about −47° C., or from about −40° C. to about −45° C. to allow forthe use of ASTM A333 grade 6 steel alloys for construction of canistersfor freeze wells. Stainless steels, such as 304 stainless steel, may beused to form freeze wells, but the cost of stainless steel is typicallymuch more than the cost of ASTM A333 grade 6 steel alloy.

In some embodiments, the metal used to form the canisters of the freezewells may be provided as pipe. In some embodiments, the metal used toform the canisters of the freeze wells may be provided in sheet form.The sheet metal may be longitudinally welded to form pipe and/or coiledtubing. Forming the canisters from sheet metal may improve the economicsof the system by allowing for coiled tubing insulation and by reducingthe equipment and manpower needed to form and install the canistersusing pipe.

A refrigeration unit may be used to reduce the temperature of formationrefrigerant to the low working temperature. In some embodiments, therefrigeration unit may utilize an ammonia vaporization cycle.Refrigeration units are available from Cool Man Inc. (Milwaukee, Wis.,U.S.A.), Gartner Refrigeration & Manufacturing (Minneapolis, Minn.,U.S.A.), and other suppliers. In some embodiments, a cascadingrefrigeration system may be utilized with a first stage of ammonia and asecond stage of carbon dioxide. The circulating refrigerant through thefreeze wells may be 30% by weight ammonia in water (aqua ammonia).Alternatively, a single stage carbon dioxide refrigeration system may beused.

In some embodiments, refrigeration systems for forming a low temperaturebarrier for a treatment area may be installed and activated beforefreeze wells are formed in the formation. As the freeze well wellboresare formed, freeze wells may be installed in the wellbores. Refrigerantmay be circulated through the wellbores soon after the freeze well isinstalled into the wellbore. Limiting the time between wellboreformation and cooling initiation may limit or inhibit cross mixing offormation water between different aquifers.

Grout may be used in combination with freeze wells to provide a barrierfor the in situ heat treatment process. The grout fills cavities (vugs)in the formation and reduces the permeability of the formation. Groutmay have higher thermal conductivity than gas and/or formation fluidthat fills cavities in the formation. Placing grout in the cavities mayallow for faster low temperature zone formation. The grout forms aperpetual barrier in the formation that may strengthen the formation.The use of grout in unconsolidated or substantially unconsolidatedformation material may allow for larger well spacing than is possiblewithout the use of grout. The combination of grout and the lowtemperature zone formed by freeze wells may constitute a double barrierfor environmental regulation purposes. In some embodiments, the grout isintroduced into the formation as a liquid, and the liquid sets in theformation to form a solid. The grout may be any type of grout, includingbut not limited to, fine cement, micro fine cement, sulfur, sulfurcement, viscous thermoplastics, and/or waxes. The grout may includesurfactants, stabilizers or other chemicals that modify the propertiesof the grout. For example, the presence of surfactant in the grout maypromote entry of the grout into small openings in the formation.

Grout may be introduced into the formation through freeze wellwellbores. The grout may be allowed to set. The integrity of the groutwall may be checked. The integrity of the grout wall may be checked bylogging techniques and/or by hydrostatic testing. If the permeability ofa grouted section is too high, additional grout may be introduced intothe formation through freeze well wellbores. After the permeability ofthe grouted section is sufficiently reduced, freeze wells may beinstalled in the freeze well wellbores.

Grout may be injected into the formation at a pressure that is high, butbelow the fracture pressure of the formation. In some embodiments,grouting is performed in 16 m increments in the freeze wellbore. Largeror smaller increments may be used if desired. In some embodiments, groutis only applied to certain portions of the formation. For example, groutmay be applied to the formation through the freeze wellbore onlyadjacent to aquifer zones and/or to relatively high permeability zones(for example, zones with a permeability greater than about 0.1 darcy).Applying grout to aquifers may inhibit migration of water from oneaquifer to a different aquifer. For grout placed in the formationthrough freeze well wellbores, the grout may inhibit water migrationbetween aquifers during formation of the low temperature zone. The groutmay also inhibit water migration between aquifers when an establishedlow temperature zone is allowed to thaw.

In some embodiments, the grout used to form a barrier may be fine cementand micro fine cement. Cement may provide structural support in theformation. Fine cement may be ASTM type 3 Portland cement. Fine cementmay be less expensive than micro fine cement. In an embodiment, a freezewellbore is formed in the formation. Selected portions of the freezewellbore are grouted using fine cement. Then, micro fine cement isinjected into the formation through the freeze wellbore. The fine cementmay reduce the permeability down to about 10 millidarcy. The micro finecement may further reduce the permeability to about 0.1 millidarcy.After the grout is introduced into the formation, a freeze wellborecanister may be inserted into the formation. The process may be repeatedfor each freeze well that will be used to form the barrier.

In some embodiments, fine cement is introduced into every other freezewellbore. Micro fine cement is introduced into the remaining wellbores.For example, grout may be used in a formation with freeze wellbores setat about 5 m spacing. A first wellbore is drilled and fine cement isintroduced into the formation through the wellbore. A freeze wellcanister is positioned in the first wellbore. A second wellbore isdrilled 10 m away from the first wellbore. Fine cement is introducedinto the formation through the second wellbore. A freeze well canisteris positioned in the second wellbore. A third wellbore is drilledbetween the first wellbore and the second wellbore. In some embodiments,grout from the first and/or second wellbores may be detected in thecuttings of the third wellbore. Micro fine cement is introduced into theformation through the third wellbore. A freeze wellbore canister ispositioned in the third wellbore. The same procedure is used to form theremaining freeze wells that will form the barrier around the treatmentarea.

In some embodiments, wax may be used to form a grout barrier. Waxbarriers may be formed in wet, dry or oil wetted formations. Liquid waxintroduced into the formation may permeate into adjacent rock andfractures in the formation. Liquid wax may permeate into rock to fillmicroscopic as well as macroscopic pores and vugs in the rock. The waxsolidifies to form a grout barrier that inhibits fluid flow into or outof a treatment area. A wax grout barrier may provide a minimal amount ofstructural support in the formation. Molten wax may reduce the strengthof poorly consolidated soil by reducing inter-grain friction so that thepoorly consolidated soil sloughs or liquefies. Poorly consolidatedlayers may be consolidated by use of cement or other binding agentsbefore introduction of molten wax.

The wax of a barrier may be a branched paraffin to, for example, inhibitbiological degradation of the wax. The wax may include stabilizers,surfactants or other chemicals that modify the physical and/or chemicalproperties of the wax. The physical properties may be tailored to meetspecific needs. The wax may melt at a relative low temperature (forexample, the wax may have a typical melting point of about 52° C.). Thetemperature at which the wax congeals may be at least 5° C., 10° C., 20°C., or 30° C. above the ambient temperature of the formation prior toany heating of the formation. When molten, the wax may have a relativelylow viscosity (for example, 4 to 10 cp at about 99° C.). The flash pointof the wax may be relatively high (for example, the flash point may beover 204° C.). The wax may have a density less than the density of waterand may have a heat capacity that is less than half the heat capacity ofwater. The solid wax may have a low thermal conductivity (for example,about 0.18 W/m° C.) so that the solid wax is a thermal insulator. Waxessuitable for forming a barrier are available as WAXFIX™ from CarterTechnologies Company (Sugar Land, Tex., U.S.A.).

In some embodiments, a wax barrier or wax barriers may be used as thebarriers for the in situ heat treatment process. In some embodiments, awax barrier may be used in conjunction with freeze wells that form a lowtemperature barrier around the treatment area. In some embodiments, thewax barrier is formed and freeze wells are installed in the wellboresused for introducing wax into the formation. In some embodiments, thewax barrier is formed in wellbores offset from the freeze wellwellbores. The wax barrier may be on the outside or the inside of thefreeze wells. In some embodiments, a wax barrier may be formed on boththe inside and outside of the freeze wells. The wax barrier may inhibitwater flow in the formation that would inhibit the formation of the lowtemperature zone by the freeze wells. In some embodiments, a wax barrieris formed in the inter-barrier zone between two freeze barriers of adouble barrier system.

Wellbores may be formed in the formation around the treatment area at aclose spacing. In some embodiments, the spacing is from about 1.5 m toabout 4 m. Low temperature heaters may be inserted in the wellbores. Theheaters may operate at temperatures from about 260° C. to about 320° C.so that the temperature at the formation face is below the pyrolysistemperature of hydrocarbons in the formation. The heaters may beactivated to heat the formation until the overlap between two adjacentheaters raises the temperature of the zone between the two heaters abovethe melting temperature of the wax. Heating the formation to obtainsuperposition of heat with a temperature above the melting temperatureof the wax may take one month, two months, or longer. After heating, theheaters may be turned off. Wax may be introduced into the wellbores toform the barrier. The wax may flow into the formation and fill anyfractures and porosity that has been heated. The wax congeals when thewax flows to cold regions beyond the heated circumference. This waxbarrier formation method may form a more complete barrier than someother methods of wax barrier formation, but the time for heating may belonger than for some of the other methods. Also, if a low temperaturebarrier is to be formed with the freeze wells placed in the wellboresused for wax injection, the freeze wells will have to remove the heatsupplied to the formation to allow for introduction of the wax. The lowtemperature barrier may take longer to form.

In some embodiments, the wax barrier may be formed using a conduitplaced in the wellbore. FIG. 18A depicts an embodiment of a system forforming a wax barrier in a formation. Wellbore 452 may extend into oneor more layers 460 below overburden 458. Wellbore 452 may be an openwellbore below underburden 458. One or more of the layers 460 mayinclude fracture systems 462. One or more of the layers may be vuggy sothat the layer or a portion of the layer has a high porosity. Conduit464 may be positioned in wellbore 452. In some embodiments, lowtemperature heater 466 may be strapped or attached to conduit 464. Insome embodiments, conduit 464 may be a heater element. Heater 466 may beoperated so that the heater does not cause pyrolysis of hydrocarbonsadjacent to the heater. At least a portion of wellbore 452 may be filledwith fluid. The fluid may be formation fluid or water. Heater 466 may beactivated to heat the fluid. A portion of the heated fluid may moveoutwards from heater 466 into the formation. The heated fluid may beinjected into the fractures and permeable vuggy zones. The heated fluidmay be injected into the fractures and permeable vuggy zones byintroducing heated wax into wellbore 452 in the annular space betweenconduit 464 and the wellbore. The introduced wax flows to the areasheated by the fluid and congeals when the fluid reaches cold regions notheated by the fluid. The wax fills fracture systems 462 and permeablevuggy pathways heated by the fluid, but the wax may not permeate througha significant portion of the rock matrix as when the hot wax isintroduced into a heated formation as described above. The wax flowsinto fracture systems 462 a sufficient distance to join with waxinjected from an adjacent well so that a barrier to fluid flow throughthe fracture systems forms when the wax congeals. A portion of wax maycongeal along the wall of a fracture or a vug without completelyblocking the fracture or filling the vug. The congealed wax may act asan insulator and allow additional liquid wax to flow beyond thecongealed portion to penetrate deeply into the formation and formblockages to fluid flow when the wax cools below the melting temperatureof the wax.

Wax in the annular space of wellbore 452 between conduit 464 and theformation may be removed through conduit by displacing the wax withwater or other fluid. Conduit 464 may be removed and a freeze well maybe installed in the wellbore. This method may use less wax than themethod described above. The heating of the fluid may be accomplished inless than a week or within a day. The small amount of heat input mayallow for quicker formation of a low temperature barrier if freeze wellsare to be positioned in the wellbores used to introduce wax into theformation.

In some embodiments, a heater may be suspended in the well without aconduit that allows for removal of excess wax from the wellbore. The waxmay be introduced into the well. After wax introduction, the heater maybe removed from the well. In some embodiments, a conduit may bepositioned in the wellbore, but a heater may not be coupled to theconduit. Hot wax may be circulated through the conduit so that the waxenters fractures systems and/or vugs adjacent to the wellbore.

In some embodiments, wax may be used during the formation of a wellboreto improve inter-zonal isolation and protect a low-pressure zone frominflow from a high-pressure zone. During wellbore formation where a highpressure zone and a low pressure zone are penetrated by a commonwellbore, it is possible for the high pressure zone to flow into the lowpressure zone and cause an underground blowout. To avoid this, thewellbore may be formed through the first zone. Then, an intermediatecasing may be set and cemented through the first zone. Setting casingmay be time consuming and expensive. Instead of setting a casing, waxmay be used to seal the first zone. The wax may also inhibit or preventmixing of high salinity brines from lower, high pressure zones withfresher brines in upper, lower pressure zones.

FIG. 18B depicts wellbore 452 drilled to a first depth in formation 758.After the surface casing for wellbore 452 is set and cemented in place,the wellbore is drilled to the first depth which passes through apermeable zone, such as an aquifer. The permeable zone may be fracturesystem 462′. In some embodiments, a heater is placed in wellbore 452 toheat the vertical interval of fracture system 462′. In some embodiments,hot fluid is circulated in wellbore 452 to heat the vertical interval offracture system 462′. After heating, molten wax is pumped down wellbore452. The molten wax flows a selected distance into fracture system 462′before the wax cools sufficiently to solidify and form a seal. Themolten wax is introduced into formation 758 at a pressure below thefracture pressure of the formation. In some embodiments, pressure ismaintained on the wellhead until the wax has solidified. In someembodiments, the wax is allowed to cool until the wax in wellbore 452 isalmost to the congealing temperature of the wax. The wax in wellbore 452may then be displaced out of the wellbore. The wax makes the portion offormation 758 near wellbore 452 into a substantially impermeable zone.Wellbore 452 may be drilled to depth through one or more permeable zonesthat are at higher pressures than the pressure in the first permeablezone, such as fracture system 462″. Congealed wax in fracture system462′ may inhibit blowout into the lower pressure zone. FIG. 18C depictswellbore 452 drilled to depth with congealed wax 492 in formation 758.

In some embodiments, wax may be used to contain and inhibit migration ina subsurface formation that has liquid hydrocarbon contaminants (forexample, compounds such as benzene, toluene, ethylbenzene and xylene)condensed in fractures in the formation. The location of thecontaminants may be surrounded with heated wax injection wells. Wax maybe introduced into the wells to form an outer wax barrier. The waxinjected into the fractures from the wax injection wells may mix withthe contaminants. The contaminants may be solubilized into the wax. Whenthe wax congeals, the contaminants may be permanently contained in thesolid wax phase.

In some embodiments, a composition that includes a cross-linkablepolymer may be used with or in addition to a wax. Such composition maybe provided to the formation as is described above for the wax. Thecomposition may be configured to react and solidify after a selectedtime in the formation, thereby allowing the composition to be providedas a liquid to the formation. The cross-linkable polymer may include,for example, acrylates, methacrylates, urethanes, and/or epoxies. Across-linking initiator may be included in the composition. Thecomposition may also include a cross-linking inhibitor. Thecross-linking inhibitor may be configured to degrade while in theformation, thereby allowing the composition to solidify.

In certain embodiments, a barrier may be formed in the formation afteran in situ heat treatment process or a solution mining process byintroducing a fluid into the formation. The in situ heat treatmentprocess may heat the treatment area and greatly increase thepermeability of the treatment area. The solution mining process mayremove material from the treatment area and greatly increase thepermeability of the treatment area. In certain embodiments, thetreatment area has an increased permeability of at least 0.1 darcy. Insome embodiments, the treatment area has an increased permeability of atleast 1 darcy, of at least 10 darcy, or of at least 100 darcy. Theincreased permeability allows the fluid to spread in the formation intofractures, microfractures, and/or pore spaces in the formation. Thefluid may include wax, bitumen, heavy oil, sulfur, polymer, saturatedsaline solution, and/or a reactant or reactants that react to form aprecipitate, solid or a high viscosity fluid in the formation. In someembodiments, bitumen, heavy oil, and/or sulfur used to form the barrierare obtained from treatment facilities of the in situ heat treatmentprocess.

The fluid may be introduced into the formation as a liquid, vapor, ormixed phase fluid. The fluid may be introduced into a portion of theformation that is at an elevated temperature. In some embodiments, thefluid is introduced into the formation through wells located near aperimeter of the treatment area. The fluid may be directed away from thetreatment area. The elevated temperature of the formation maintains orallows the fluid to have a low viscosity so that the fluid moves awayfrom the wells. A portion of the fluid may spread outwards in theformation towards a cooler portion of the formation. In the coolerportion of the formation, the viscosity of the fluid increases, aportion of the fluid precipitates, and/or the fluid solidifies orthickens so that the fluid forms the barrier to flow of formation fluidinto or out of the treatment area.

In some embodiments, a low temperature barrier formed by freeze wellssurrounds all or a portion of the treatment area. As the fluidintroduced into the formation approaches the low temperature barrier,the temperature of the formation becomes colder. The colder temperatureincreases the viscosity of the fluid, enhances precipitation, and/orsolidifies the fluid to form the barrier to the flow of formation fluidinto or out of the formation. The fluid may remain in the formation as ahighly viscous fluid or a solid after the low temperature barrier hasdissipated.

In certain embodiments, saturated saline solution is introduced into theformation. Components in the saturated saline solution may precipitateout of solution when the solution reaches a colder temperature. Thesolidified particles may form the barrier to the flow of formation fluidinto or out of the formation. The solidified components may besubstantially insoluble in formation fluid.

In certain embodiments, brine is introduced into the formation as areactant. A second reactant, such a carbon dioxide may be introducedinto the formation to react with the brine. The reaction may generate amineral complex that grows in the formation. The mineral complex may besubstantially insoluble to formation fluid. In an embodiment, the brinesolution includes a sodium and aluminum solution. The second reactantintroduced in the formation is carbon dioxide. The carbon dioxide reactswith the brine solution to produce dawsonite. The minerals may solidifyand form the barrier to the flow of formation fluid into or out of theformation.

In some embodiments, the barrier may be formed using sulfur. Moltensulfur may be introduced into the formation through wells located nearthe perimeter of the treatment area. At least a portion of the sulfurspreads outwards from the treatment area towards a cooler portion of theformation. The introduced sulfur spreads outward and solidifies in theformation to form a sulfur barrier. The solidified sulfur in theformation forms a barrier to formation fluid flow into or out of thetreatment area.

A temperature monitoring system may be installed in wellbores of freezewells and/or in monitor wells adjacent to the freeze wells to monitorthe temperature profile of the freeze wells and/or the low temperaturezone established by the freeze wells. The monitoring system may be usedto monitor progress of low temperature zone formation. The monitoringsystem may be used to determine the location of high temperature areas,potential breakthrough locations, or breakthrough locations after thelow temperature zone has formed. Periodic monitoring of the temperatureprofile of the freeze wells and/or low temperature zone established bythe freeze wells may allow additional cooling to be provided topotential trouble areas before breakthrough occurs. Additional coolingmay be provided at or adjacent to breakthroughs and high temperatureareas to ensure the integrity of the low temperature zone around thetreatment area. Additional cooling may be provided by increasingrefrigerant flow through selected freeze wells, installing an additionalfreeze well or freeze wells, and/or by providing a cryogenic fluid, suchas liquid nitrogen, to the high temperature areas. Providing additionalcooling to potential problem areas before breakthrough occurs may bemore time efficient and cost efficient than sealing a breach, reheatinga portion of the treatment area that has been cooled by influx of fluid,and/or remediating an area outside of the breached frozen barrier.

In some embodiments, a traveling thermocouple may be used to monitor thetemperature profile of selected freeze wells or monitor wells. In someembodiments, the temperature monitoring system includes thermocouplesplaced at discrete locations in the wellbores of the freeze wells, inthe freeze wells, and/or in the monitoring wells. In some embodiments,the temperature monitoring system comprises a fiber optic temperaturemonitoring system.

Fiber optic temperature monitoring systems are available from Sensomet(London, United Kingdom), Sensa (Houston, Tex., U.S.A.), Luna Energy(Blacksburg, Va., U.S.A.), Lios Technology GMBH (Cologne, Germany),Oxford Electronics Ltd. (Hampshire, United Kingdom), and Sabeus SensorSystems (Calabasas, Calif., U.S.A.). The fiber optic temperaturemonitoring system includes a data system and one or more fiber opticcables. The data system includes one or more lasers for sending light tothe fiber optic cable; and one or more computers, software andperipherals for receiving, analyzing, and outputting data. The datasystem may be coupled to one or more fiber optic cables.

A single fiber optic cable may be several kilometers long. The fiberoptic cable may be installed in many freeze wells and/or monitor wells.In some embodiments, two fiber optic cables may be installed in eachfreeze well and/or monitor well. The two fiber optic cables may becoupled. Using two fiber optic cables per well allows for compensationdue to optical losses that occur in the wells and allows for betteraccuracy of measured temperature profiles.

The fiber optic temperature monitoring system may be used to detect thelocation of a breach or a potential breach in a frozen barrier. Thesearch for potential breaches may be performed at scheduled intervals,for example, every two or three months. To determine the location of thebreach or potential breach, flow of formation refrigerant to the freezewells of interest is stopped. In some embodiments, the flow of formationrefrigerant to all of the freeze wells is stopped. The rise in thetemperature profiles, as well as the rate of change of the temperatureprofiles, provided by the fiber optic temperature monitoring system foreach freeze well can be used to determine the location of any breachesor hot spots in the low temperature zone maintained by the freeze wells.The temperature profile monitored by the fiber optic temperaturemonitoring system for the two freeze wells closest to the hot spot orfluid flow will show the quickest and greatest rise in temperature. Atemperature change of a few degrees Centigrade in the temperatureprofiles of the freeze wells closest to a troubled area may besufficient to isolate the location of the trouble area. The shut downtime of flow of circulation fluid in the freeze wells of interest neededto detect breaches, potential breaches, and hot spots may be on theorder of a few hours or days, depending on the well spacing and theamount of fluid flow affecting the low temperature zone.

Fiber optic temperature monitoring systems may also be used to monitortemperatures in heated portions of the formation during in situ heattreatment processes. The fiber of a fiber optic cable used in the heatedportion of the formation may be clad with a reflective material tofacilitate retention of a signal or signals transmitted down the fiber.In some embodiments, the fiber is clad with gold, copper, nickel,aluminum and/or alloys thereof. The cladding may be formed of a materialthat is able to withstand chemical and temperature conditions in theheated portion of the formation. For example, gold cladding may allow anoptical sensor to be used up to temperatures of 700° C. In someembodiments, the fiber is clad with aluminum. The fiber may be dipped inor run through a bath of liquid aluminum. The clad fiber may then beallowed to cool to secure the aluminum to the fiber. The gold oraluminum cladding may reduce hydrogen darkening of the optical fiber.

A potential source of heat loss from the heated formation is due toreflux in wells. Refluxing occurs when vapors condense in a well andflow into a portion of the well adjacent to the heated portion of theformation. Vapors may condense in the well adjacent to the overburden ofthe formation to form condensed fluid. Condensed fluid flowing into thewell adjacent to the heated formation absorbs heat from the formation.Heat absorbed by condensed fluids cools the formation and necessitatesadditional energy input into the formation to maintain the formation ata desired temperature. Some fluids that condense in the overburden andflow into the portion of the well adjacent to the heated formation mayreact to produce undesired compounds and/or coke. Inhibiting fluids fromrefluxing may significantly improve the thermal efficiency of the insitu heat treatment system and/or the quality of the product producedfrom the in situ heat treatment system.

For some well embodiments, the portion of the well adjacent to theoverburden section of the formation is cemented to the formation. Insome well embodiments, the well includes packing material placed nearthe transition from the heated section of the formation to theoverburden. The packing material inhibits formation fluid from passingfrom the heated section of the formation into the section of thewellbore adjacent to the overburden. Cables, conduits, devices, and/orinstruments may pass through the packing material, but the packingmaterial inhibits formation fluid from passing up the wellbore adjacentto the overburden section of the formation.

In some embodiments, a gas may be introduced into the formation throughwellbores to inhibit reflux in the wellbores. In some embodiments, gasmay be introduced into wellbores that include baffle systems to inhibitreflux of fluid in the wellbores. The gas may be carbon dioxide,methane, nitrogen or other desired gas.

In some well embodiments, a ball type reflux baffle system may be usedin heater wells to inhibit reflux. FIG. 19 depicts an embodiment of balltype reflux baffle system positioned in a cased portion of a heaterwell. Ball type reflux baffle may include insert 468, and balls 470. Aportion of heater element 472 passes through insert 468. The portion ofheater element 472 that passes through insert 468 is a portion of theheater element that does not heat to a high temperature. Insert 468 maybe made of metal, plastic and/or steel able to withstand temperatures ofover 160° C. In an embodiment, insert 468 is made of phenolic resin.

Insert 468 may be guided down the casing of the wellbore using a coiltubing guide string. Insert 468 may be set in position using slips thatfit in one or more indentions in the insert, using protrusions of theinsert that fit in one or more recesses in the casing, or the insert mayrest on a shoulder of the casing. After removal of the coil tubing guidestring, balls 470 may be dropped down the casing onto insert 468. Ballsmay be made of any desired material able to withstand temperatures ofover 160° C. In some embodiments, balls 470 are made of silicon nitride.Balls of varying diameters may be used. Balls 470 inhibit fluidconvection.

During the in situ heat treatment process, heater element 472 may needto be pulled from the well. When heater element 472 is removed from thewell, balls 470 may pass through insert 468 to the bottom of the well.Another heater element may be installed in the well, and additionalballs may be dropped down the well to land on insert 468.

In some embodiments, one or more circular baffles may be coupled to aportion of a heating element to inhibit convection of fluid. The bafflesmay substantially fill the annular space between the heating element andthe casing. The baffles may be made of an electrically insulativematerial such as a ceramic, or plastic. In some embodiments, the bafflesmay be made of fiberglass or silicon nitride. The baffles may positionthe heating element in the center of the casing.

The ball type baffle system and/or the circular baffle system may workbetter if a gas purge is introduced into the wellbore. The gas purge maymaintain sufficient pressure in the wellbore to inhibit fluid flow fromthe heated portion of the formation into the wellbore. The gas purge mayenhance heat exchange at the baffle system to help maintain a topportion of the baffle system colder than the lower portion of the bafflesystem.

The flow of production fluid up the well to the surface is desired forsome types of wells, especially for production wells. Flow of productionfluid up the well is also desirable for some heater wells that are usedto control pressure in the formation. The overburden, or a conduit inthe well used to transport formation fluid from the heated portion ofthe formation to the surface, may be heated to inhibit condensation onor in the conduit. Providing heat in the overburden, however, may becostly and/or may lead to increased cracking or coking of formationfluid as the formation fluid is being produced from the formation.

To avoid the need to heat the overburden or to heat the conduit passingthrough the overburden, one or more diverters may be placed in thewellbore to inhibit fluid from refluxing into the wellbore adjacent tothe heated portion of the formation. In some embodiments, the diverterretains fluid above the heated portion of the formation. Fluids retainedin the diverter may be removed from the diverter using a pump, gaslifting, and/or other fluid removal technique. In certain embodiments,two or more diverters that retain fluid above the heated portion of theformation may be located in the production well. Two or more divertersprovide a simple way of separating initial fractions of condensed fluidproduced from the in situ heat treatment system. A pump may be placed ineach of the diverters to remove condensed fluid from the diverters.

In some embodiments, the diverter directs fluid to a sump below theheated portion of the formation. An inlet for a lift system may belocated in the sump. In some embodiments, the intake of the lift systemis located in casing in the sump. In some embodiments, the intake of thelift system is located in an open wellbore. The sump is below the heatedportion of the formation. The intake of the pump may be located 1 m, 5m, 10 m, 20 m or more below the deepest heater used to heat the heatedportion of the formation. The sump may be at a cooler temperature thanthe heated portion of the formation. The sump may be more than 10° C.,more than 50° C., more than 75° C., or more than 100° C. below thetemperature of the heated portion of the formation. A portion of thefluid entering the sump may be liquid. A portion of the fluid enteringthe sump may condense within the sump. The lift system moves the fluidin the sump to the surface.

Production well lift systems may be used to efficiently transportformation fluid from the bottom of the production wells to the surface.Production well lift systems may provide and maintain the maximumrequired well drawdown (minimum reservoir producing pressure) andproducing rates. The production well lift systems may operateefficiently over a wide range of high temperature/multiphase fluids(gas/vapor/steam/water/hydrocarbon liquids) and production ratesexpected during the life of a typical project. Production well liftsystems may include dual concentric rod pump lift systems, chamber liftsystems and other types of lift systems.

Temperature limited heaters may be in configurations and/or may includematerials that provide automatic temperature limiting properties for theheater at certain temperatures. In certain embodiments, ferromagneticmaterials are used in temperature limited heaters. Ferromagneticmaterial may self-limit temperature at or near the Curie temperature ofthe material to provide a reduced amount of heat at or near the Curietemperature when a time-varying current is applied to the material. Incertain embodiments, the ferromagnetic material self-limits temperatureof the temperature limited heater at a selected temperature that isapproximately the Curie temperature. In certain embodiments, theselected temperature is within about 35° C., within about 25° C., withinabout 20° C., or within about 10° C. of the Curie temperature. Incertain embodiments, ferromagnetic materials are coupled with othermaterials (for example, highly conductive materials, high strengthmaterials, corrosion resistant materials, or combinations thereof) toprovide various electrical and/or mechanical properties. Some parts ofthe temperature limited heater may have a lower resistance (caused bydifferent geometries and/or by using different ferromagnetic and/ornon-ferromagnetic materials) than other parts of the temperature limitedheater. Having parts of the temperature limited heater with variousmaterials and/or dimensions allows for tailoring the desired heat outputfrom each part of the heater.

Temperature limited heaters may be more reliable than other heaters.Temperature limited heaters may be less apt to break down or fail due tohot spots in the formation. In some embodiments, temperature limitedheaters allow for substantially uniform heating of the formation. Insome embodiments, temperature limited heaters are able to heat theformation more efficiently by operating at a higher average heat outputalong the entire length of the heater. The temperature limited heateroperates at the higher average heat output along the entire length ofthe heater because power to the heater does not have to be reduced tothe entire heater, as is the case with typical constant wattage heaters,if a temperature along any point of the heater exceeds, or is about toexceed, a maximum operating temperature of the heater. Heat output fromportions of a temperature limited heater approaching a Curie temperatureof the heater automatically reduces without controlled adjustment of thetime-varying current applied to the heater. The heat outputautomatically reduces due to changes in electrical properties (forexample, electrical resistance) of portions of the temperature limitedheater. Thus, more power is supplied by the temperature limited heaterduring a greater portion of a heating process.

In certain embodiments, the system including temperature limited heatersinitially provides a first heat output and then provides a reduced(second heat output) heat output, near, at, or above the Curietemperature of an electrically resistive portion of the heater when thetemperature limited heater is energized by a time-varying current. Thefirst heat output is the heat output at temperatures below which thetemperature limited heater begins to self-limit. In some embodiments,the first heat output is the heat output at a temperature about 50° C.,about 75° C., about 100° C., or about 125° C. below the Curietemperature of the ferromagnetic material in the temperature limitedheater.

The temperature limited heater may be energized by time-varying current(alternating current or modulated direct current) supplied at thewellhead. The wellhead may include a power source and other components(for example, modulation components, transformers, and/or capacitors)used in supplying power to the temperature limited heater. Thetemperature limited heater may be one of many heaters used to heat aportion of the formation.

In certain embodiments, the temperature limited heater includes aconductor that operates as a skin effect or proximity effect heater whentime-varying current is applied to the conductor. The skin effect limitsthe depth of current penetration into the interior of the conductor. Forferromagnetic materials, the skin effect is dominated by the magneticpermeability of the conductor. The relative magnetic permeability offerromagnetic materials is typically between 10 and 1000 (for example,the relative magnetic permeability of ferromagnetic materials istypically at least 10 and may be at least 50, 100, 500, 1000 orgreater). As the temperature of the ferromagnetic material is raisedabove the Curie temperature and/or as the applied electrical current isincreased, the magnetic permeability of the ferromagnetic materialdecreases substantially and the skin depth expands rapidly (for example,the skin depth expands as the inverse square root of the magneticpermeability). The reduction in magnetic permeability results in adecrease in the AC or modulated DC resistance of the conductor near, at,or above the Curie temperature and/or as the applied electrical currentis increased. When the temperature limited heater is powered by asubstantially constant current source, portions of the heater thatapproach, reach, or are above the Curie temperature may have reducedheat dissipation. Sections of the temperature limited heater that arenot at or near the Curie temperature may be dominated by skin effectheating that allows the heater to have high heat dissipation due to ahigher resistive load.

Curie temperature heaters have been used in soldering equipment, heatersfor medical applications, and heating elements for ovens (for example,pizza ovens). Some of these uses are disclosed in U.S. Pat. No.5,579,575 to Lamome et al.; U.S. Pat. No. 5,065,501 to Henschen et al.;and U.S. Pat. No. 5,512,732 to Yagnik et al., all of which areincorporated by reference as if fully set forth herein. U.S. Pat. No.4,849,611 to Whitney et al., which is incorporated by reference as iffully set forth herein, describes a plurality of discrete, spaced-apartheating units including a reactive component, a resistive heatingcomponent, and a temperature responsive component.

An advantage of using the temperature limited heater to heathydrocarbons in the formation is that the conductor is chosen to have aCurie temperature in a desired range of temperature operation. Operationwithin the desired operating temperature range allows substantial heatinjection into the formation while maintaining the temperature of thetemperature limited heater, and other equipment, below design limittemperatures. Design limit temperatures are temperatures at whichproperties such as corrosion, creep, and/or deformation are adverselyaffected. The temperature limiting properties of the temperature limitedheater inhibit overheating or burnout of the heater adjacent to lowthermal conductivity “hot spots” in the formation. In some embodiments,the temperature limited heater is able to lower or control heat outputand/or withstand heat at temperatures above 25° C., 37° C., 100° C.,250° C., 500° C., 700° C., 800° C., 900° C., or higher up to 1131° C.,depending on the materials used in the heater.

The temperature limited heater allows for more heat injection into theformation than constant wattage heaters because the energy input intothe temperature limited heater does not have to be limited toaccommodate low thermal conductivity regions adjacent to the heater. Forexample, in Green River oil shale there is a difference of at least afactor of 3 in the thermal conductivity of the lowest richness oil shalelayers and the highest richness oil shale layers. When heating such aformation, substantially more heat is transferred to the formation withthe temperature limited heater than with the conventional heater that islimited by the temperature at low thermal conductivity layers. The heatoutput along the entire length of the conventional heater needs toaccommodate the low thermal conductivity layers so that the heater doesnot overheat at the low thermal conductivity layers and burn out. Theheat output adjacent to the low thermal conductivity layers that are athigh temperature will reduce for the temperature limited heater, but theremaining portions of the temperature limited heater that are not athigh temperature will still provide high heat output. Because heatersfor heating hydrocarbon formations typically have long lengths (forexample, at least 10 m, 100 m, 300 m, 500 m, 1 km or more up to about 10km), the majority of the length of the temperature limited heater may beoperating below the Curie temperature while only a few portions are ator near the Curie temperature of the temperature limited heater.

The use of temperature limited heaters allows for efficient transfer ofheat to the formation. Efficient transfer of heat allows for reductionin time needed to heat the formation to a desired temperature. Forexample, in Green River oil shale, pyrolysis typically requires 9.5years to 10 years of heating when using a 12 m heater well spacing withconventional constant wattage heaters. For the same heater spacing,temperature limited heaters may allow a larger average heat output whilemaintaining heater equipment temperatures below equipment design limittemperatures. Pyrolysis in the formation may occur at an earlier timewith the larger average heat output provided by temperature limitedheaters than the lower average heat output provided by constant wattageheaters. For example, in Green River oil shale, pyrolysis may occur in 5years using temperature limited heaters with a 12 m heater well spacing.Temperature limited heaters counteract hot spots due to inaccurate wellspacing or drilling where heater wells come too close together. Incertain embodiments, temperature limited heaters allow for increasedpower output over time for heater wells that have been spaced too farapart, or limit power output for heater wells that are spaced too closetogether. Temperature limited heaters also supply more power in regionsadjacent the overburden and underburden to compensate for temperaturelosses in these regions.

Temperature limited heaters may be advantageously used in many types offormations. For example, in tar sands formations or relatively permeableformations containing heavy hydrocarbons, temperature limited heatersmay be used to provide a controllable low temperature output forreducing the viscosity of fluids, mobilizing fluids, and/or enhancingthe radial flow of fluids at or near the wellbore or in the formation.Temperature limited heaters may be used to inhibit excess coke formationdue to overheating of the near wellbore region of the formation.

The use of temperature limited heaters, in some embodiments, eliminatesor reduces the need for expensive temperature control circuitry. Forexample, the use of temperature limited heaters eliminates or reducesthe need to perform temperature logging and/or the need to use fixedthermocouples on the heaters to monitor potential overheating at hotspots.

In certain embodiments, phase transformation (for example, crystallinephase transformation or a change in the crystal structure) of materialsused in a temperature limited heater change the selected temperature atwhich the heater self-limits. Ferromagnetic material used in thetemperature limited heater may have a phase transformation (for example,a transformation from ferrite to austenite) that decreases the magneticpermeability of the ferromagnetic material. This reduction in magneticpermeability is similar to reduction in magnetic permeability due to themagnetic transition of the ferromagnetic material at the Curietemperature. The Curie temperature is the magnetic transitiontemperature of the ferrite phase of the ferromagnetic material. Thereduction in magnetic permeability results in a decrease in the AC ormodulated DC resistance of the temperature limited heater near, at, orabove the temperature of the phase transformation and/or the Curietemperature of the ferromagnetic material.

The phase transformation of the ferromagnetic material may occur over atemperature range. The temperature range of the phase transformationdepends on the ferromagnetic material and may vary, for example, over arange of about 20° C. to a range of about 200° C. Because the phasetransformation takes place over a temperature range, the reduction inthe magnetic permeability due to the phase transformation takes placeover the temperature range. The reduction in magnetic permeability mayalso occur irregularly over the temperature range of the phasetransformation. In some embodiments, the phase transformation back tothe lower temperature phase of the ferromagnetic material is slower thanthe phase transformation to the higher temperature phase (for example,the transition from austenite back to ferrite is slower than thetransition from ferrite to austenite). The slower phase transformationback to the lower temperature phase may cause irregular operation of theheater at or near the phase transformation temperature range.

In some embodiments, the phase transformation temperature range overlapswith the reduction in the magnetic permeability when the temperatureapproaches the Curie temperature of the ferromagnetic material. Theoverlap may produce a slower drop in electrical resistance versustemperature than if the reduction in magnetic permeability is solely dueto the temperature approaching the Curie temperature. The overlap mayalso produce irregular behavior of the temperature limited heater nearthe Curie temperature and/or in the phase transformation temperaturerange.

In certain embodiments, alloy additions are made to the ferromagneticmaterial to adjust the temperature range of the phase transformation.For example, adding carbon to the ferromagnetic material may increasethe phase transformation temperature range and lower the onsettemperature of the phase transformation. Adding titanium to theferromagnetic material may increase the onset temperature of the phasetransformation and decrease the phase transformation temperature range.Alloy compositions may be adjusted to provide desired Curie temperatureand phase transformation properties for the ferromagnetic material. Thealloy composition of the ferromagnetic material may be chosen based ondesired properties for the ferromagnetic material (such as, but notlimited to, magnetic permeability transition temperature or temperaturerange, resistance versus temperature profile, or power output). Additionof titanium may allow higher Curie temperatures to be obtained whenadding cobalt to 410 stainless steel by raising the ferrite to austenitephase transformation temperature range to a temperature range that isabove, or well above, the Curie temperature of the ferromagneticmaterial.

In certain embodiments, the temperature limited heater is deformationtolerant. Localized movement of material in the wellbore may result inlateral stresses on the heater that could deform its shape. Locationsalong a length of the heater at which the wellbore approaches or closeson the heater may be hot spots where a standard heater overheats and hasthe potential to burn out. These hot spots may lower the yield strengthand creep strength of the metal, allowing crushing or deformation of theheater. The temperature limited heater may be formed with S curves (orother non-linear shapes) that accommodate deformation of the temperaturelimited heater without causing failure of the heater.

In some embodiments, temperature limited heaters are more economical tomanufacture or make than standard heaters. Typical ferromagneticmaterials include iron, carbon steel, or ferritic stainless steel. Suchmaterials are inexpensive as compared to nickel-based heating alloys(such as nichrome, Kanthal™ (Bulten-Kanthal AB, Sweden), and/or LOHM™(Driver-Harris Company, Harrison, N.J., U.S.A.)) typically used ininsulated conductor (mineral insulated cable) heaters. In one embodimentof the temperature limited heater, the temperature limited heater ismanufactured in continuous lengths as an insulated conductor heater tolower costs and improve reliability.

In some embodiments, the temperature limited heater is placed in theheater well using a coiled tubing rig. A heater that can be coiled on aspool may be manufactured by using metal such as ferritic stainlesssteel (for example, 409 stainless steel) that is welded using electricalresistance welding (ERW). To form a heater section, a metal strip from aroll is passed through a first former where it is shaped into a tubularand then longitudinally welded using ERW. The tubular is passed througha second former where a conductive strip (for example, a copper strip)is applied, drawn down tightly on the tubular through a die, andlongitudinally welded using ERW. A sheath may be formed bylongitudinally welding a support material (for example, steel such as347H or 347HH) over the conductive strip material. The support materialmay be a strip rolled over the conductive strip material. An overburdensection of the heater may be formed in a similar manner.

FIG. 20 depicts an embodiment of a device for longitudinal welding of atubular using ERW. Metal strip 474 is shaped into tubular form as itpasses through ERW coil 476. Metal strip 474 is then welded into atubular inside shield 478. As metal strip 474 is joined inside shield478, inert gas (for example, argon or another suitable welding gas) isprovided inside the forming tubular by gas inlets 480. Flushing thetubular with inert gas inhibits oxidation of the tubular as it isformed. Shield 478 may have window 482. Window 482 allows an operator tovisually inspect the welding process. Tubular 484 is formed by thewelding process.

In certain embodiments, the overburden section uses a non-ferromagneticmaterial such as 304 stainless steel or 316 stainless steel instead of aferromagnetic material. The heater section and overburden section may becoupled using standard techniques such as butt welding using an orbitalwelder. In some embodiments, the overburden section material (thenon-ferromagnetic material) may be pre-welded to the ferromagneticmaterial before rolling. The pre-welding may eliminate the need for aseparate coupling step (for example, butt welding). In an embodiment, aflexible cable (for example, a furnace cable such as a MGT 1000 furnacecable) may be pulled through the center after forming the tubularheater. An end bushing on the flexible cable may be welded to thetubular heater to provide an electrical current return path. The tubularheater, including the flexible cable, may be coiled onto a spool beforeinstallation into a heater well. In an embodiment, the temperaturelimited heater is installed using the coiled tubing rig. The coiledtubing rig may place the temperature limited heater in a deformationresistant container in the formation. The deformation resistantcontainer may be placed in the heater well using conventional methods.

Temperature limited heaters may be used for heating hydrocarbonformations including, but not limited to, oil shale formations, coalformations, tar sands formations, and formations with heavy viscousoils. Temperature limited heaters may also be used in the field ofenvironmental remediation to vaporize or destroy soil contaminants.Embodiments of temperature limited heaters may be used to heat fluids ina wellbore or sub-sea pipeline to inhibit deposition of paraffin orvarious hydrates. In some embodiments, a temperature limited heater isused for solution mining a subsurface formation (for example, an oilshale or a coal formation). In certain embodiments, a fluid (forexample, molten salt) is placed in a wellbore and heated with atemperature limited heater to inhibit deformation and/or collapse of thewellbore. In some embodiments, the temperature limited heater isattached to a sucker rod in the wellbore or is part of the sucker roditself. In some embodiments, temperature limited heaters are used toheat a near wellbore region to reduce near wellbore oil viscosity duringproduction of high viscosity crude oils and during transport of highviscosity oils to the surface. In some embodiments, a temperaturelimited heater enables gas lifting of a viscous oil by lowering theviscosity of the oil without coking the oil. Temperature limited heatersmay be used in sulfur transfer lines to maintain temperatures betweenabout 110° C. and about 130° C.

The ferromagnetic alloy or ferromagnetic alloys used in the temperaturelimited heater determine the Curie temperature of the heater. Curietemperature data for various metals is listed in “American Institute ofPhysics Handbook,” Second Edition, McGraw-Hill, pages 5-170 through5-176. Ferromagnetic conductors may include one or more of theferromagnetic elements (iron, cobalt, and nickel) and/or alloys of theseelements. In some embodiments, ferromagnetic conductors includeiron-chromium (Fe—Cr) alloys that contain tungsten (W) (for example,HCM12A and SAVE12 (Sumitomo Metals Co., Japan) and/or iron alloys thatcontain chromium (for example, Fe—Cr alloys, Fe—Cr—W alloys, Fe—Cr—V(vanadium) alloys, and Fe—Cr—Nb (Niobium) alloys). Of the three mainferromagnetic elements, iron has a Curie temperature of approximately770° C.; cobalt (Co) has a Curie temperature of approximately 1131° C.;and nickel has a Curie temperature of approximately 358° C. Aniron-cobalt alloy has a Curie temperature higher than the Curietemperature of iron. For example, iron-cobalt alloy with 2% by weightcobalt has a Curie temperature of approximately 800° C.; iron-cobaltalloy with 12% by weight cobalt has a Curie temperature of approximately900° C.; and iron-cobalt alloy with 20% by weight cobalt has a Curietemperature of approximately 950° C. Iron-nickel alloy has a Curietemperature lower than the Curie temperature of iron. For example,iron-nickel alloy with 20% by weight nickel has a Curie temperature ofapproximately 720° C., and iron-nickel alloy with 60% by weight nickelhas a Curie temperature of approximately 560° C.

Some non-ferromagnetic elements used as alloys raise the Curietemperature of iron. For example, an iron-vanadium alloy with 5.9% byweight vanadium has a Curie temperature of approximately 815° C. Othernon-ferromagnetic elements (for example, carbon, aluminum, copper,silicon, and/or chromium) may be alloyed with iron or otherferromagnetic materials to lower the Curie temperature.Non-ferromagnetic materials that raise the Curie temperature may becombined with non-ferromagnetic materials that lower the Curietemperature and alloyed with iron or other ferromagnetic materials toproduce a material with a desired Curie temperature and other desiredphysical and/or chemical properties. In some embodiments, the Curietemperature material is a ferrite such as NiFe₂O₄. In other embodiments,the Curie temperature material is a binary compound such as FeNi₃ orFe₃Al.

In some embodiments, the improved alloy includes carbon, cobalt, iron,manganese, silicon, or mixtures thereof. In certain embodiments, theimproved alloy includes, by weight: about 0.1% to about 10% cobalt;about 0.1% carbon, about 0.5% manganese, about 0.5% silicon, with thebalance being iron. In certain embodiments, the improved alloy includes,by weight: about 0.1% to about 10% cobalt; about 0.1% carbon, about 0.5%manganese, about 0.5% silicon, with the balance being iron.

In some embodiments, the improved alloy includes chromium, carbon,cobalt, iron, manganese, silicon, titanium, vanadium, or mixturesthereof. In certain embodiments, the improved alloy includes, by weight:about 5% to about 20% cobalt, about 0.1% carbon, about 0.5% manganese,about 0.5% silicon, about 0.1% to about 2% vanadium with the balancebeing iron. In some embodiments, the improved alloy includes, by weight:about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% toabout 0.5% manganese, above 0% to about 15% cobalt, above 0% to about 2%vanadium, above 0% to about 1% titanium, with the balance being iron. Insome embodiments, the improved alloy includes, by weight: about 12%chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about0.5% manganese, above 0% to about 2% vanadium, above 0% to about 1%titanium, with the balance being iron. In some embodiments, the improvedalloy includes, by weight: about 12% chromium, about 0.1% carbon, about0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 2%vanadium, with the balance being iron. In certain embodiments, theimproved alloy includes, by weight: about 12% chromium, about 0.1%carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0%to about 15% cobalt, above 0% to about 1% titanium, with the balancebeing iron. In certain embodiments, the improved alloy includes, byweight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about0.1% to about 0.5% manganese, above 0% to about 15% cobalt, with thebalance being iron. The addition of vanadium may allow for use of higheramounts of cobalt in the improved alloy.

Certain embodiments of temperature limited heaters may include more thanone ferromagnetic material. Such embodiments are within the scope ofembodiments described herein if any conditions described herein apply toat least one of the ferromagnetic materials in the temperature limitedheater.

Ferromagnetic properties generally decay as the Curie temperature isapproached. The “Handbook of Electrical Heating for Industry” by C.James Erickson (IEEE Press, 1995) shows a typical curve for 1% carbonsteel (steel with 1% carbon by weight). The loss of magneticpermeability starts at temperatures above 650° C. and tends to becomplete when temperatures exceed 730° C. Thus, the self-limitingtemperature may be somewhat below the actual Curie temperature of theferromagnetic conductor. The skin depth for current flow in 1% carbonsteel is 0.132 cm at room temperature and increases to 0.445 cm at 720°C. From 720° C. to 730° C., the skin depth sharply increases to over 2.5cm. Thus, a temperature limited heater embodiment using 1% carbon steelbegins to self-limit between 650° C. and 730° C.

Skin depth generally defines an effective penetration depth oftime-varying current into the conductive material. In general, currentdensity decreases exponentially with distance from an outer surface tothe center along the radius of the conductor. The depth at which thecurrent density is approximately 1/e of the surface current density iscalled the skin depth. For a solid cylindrical rod with a diameter muchgreater than the penetration depth, or for hollow cylinders with a wallthickness exceeding the penetration depth, the skin depth, δ, is:δ=1981.5*(ρ/(μ*f))^(1/2);  (3)in which:

-   -   δ=skin depth in inches;    -   ρ=resistivity at operating temperature (ohm-cm);    -   μ=relative magnetic permeability; and    -   f=frequency (Hz).

EQN. 3 is obtained from “Handbook of Electrical Heating for Industry” byC. James Erickson (IEEE Press, 1995). For most metals, resistivity (ρ)increases with temperature. The relative magnetic permeability generallyvaries with temperature and with current. Additional equations may beused to assess the variance of magnetic permeability and/or skin depthon both temperature and/or current. The dependence of μ on currentarises from the dependence of μ on the electromagnetic field.

Materials used in the temperature limited heater may be selected toprovide a desired turndown ratio. Turndown ratios of at least 1.1:1,2:1, 3:1, 4:1, 5:1, 10:1, 30:1, or 50:1 may be selected for temperaturelimited heaters. Larger turndown ratios may also be used. A selectedturndown ratio may depend on a number of factors including, but notlimited to, the type of formation in which the temperature limitedheater is located (for example, a higher turndown ratio may be used foran oil shale formation with large variations in thermal conductivitybetween rich and lean oil shale layers) and/or a temperature limit ofmaterials used in the wellbore (for example, temperature limits ofheater materials). In some embodiments, the turndown ratio is increasedby coupling additional copper or another good electrical conductor tothe ferromagnetic material (for example, adding copper to lower theresistance above the Curie temperature).

The temperature limited heater may provide a maximum heat output (poweroutput) below the Curie temperature of the heater. In certainembodiments, the maximum heat output is at least 400 W/m (Watts permeter), 600 W/m, 700 W/m, 800 W/m, or higher up to 2000 W/m. Thetemperature limited heater reduces the amount of heat output by asection of the heater when the temperature of the section of the heaterapproaches or is above the Curie temperature. The reduced amount of heatmay be substantially less than the heat output below the Curietemperature. In some embodiments, the reduced amount of heat is at most400 W/m, 200 W/m, 100 W/m or may approach 0 W/m.

In certain embodiments, the temperature limited heater operatessubstantially independently of the thermal load on the heater in acertain operating temperature range. “Thermal load” is the rate thatheat is transferred from a heating system to its surroundings. It is tobe understood that the thermal load may vary with temperature of thesurroundings and/or the thermal conductivity of the surroundings. In anembodiment, the temperature limited heater operates at or above theCurie temperature of the temperature limited heater such that theoperating temperature of the heater increases at most by 3° C., 2° C.,1.5° C., 1° C., or 0.5° C. for a decrease in thermal load of 1 W/mproximate to a portion of the heater. In certain embodiments, thetemperature limited heater operates in such a manner at a relativelyconstant current.

The AC or modulated DC resistance and/or the heat output of thetemperature limited heater may decrease as the temperature approachesthe Curie temperature and decrease sharply near or above the Curietemperature due to the Curie effect. In certain embodiments, the valueof the electrical resistance or heat output above or near the Curietemperature is at most one-half of the value of electrical resistance orheat output at a certain point below the Curie temperature. In someembodiments, the heat output above or near the Curie temperature is atmost 90%, 70%, 50%, 30%, 20%, 10%, or less (down to 1%) of the heatoutput at a certain point below the Curie temperature (for example, 30°C. below the Curie temperature, 40° C. below the Curie temperature, 50°C. below the Curie temperature, or 100° C. below the Curie temperature).In certain embodiments, the electrical resistance above or near theCurie temperature decreases to 80%, 70%, 60%, 50%, or less (down to 1%)of the electrical resistance at a certain point below the Curietemperature (for example, 30° C. below the Curie temperature, 40° C.below the Curie temperature, 50° C. below the Curie temperature, or 100°C. below the Curie temperature).

In some embodiments, AC frequency is adjusted to change the skin depthof the ferromagnetic material. For example, the skin depth of 1% carbonsteel at room temperature is 0.132 cm at 60 Hz, 0.0762 cm at 180 Hz, and0.046 cm at 440 Hz. Since heater diameter is typically larger than twicethe skin depth, using a higher frequency (and thus a heater with asmaller diameter) reduces heater costs. For a fixed geometry, the higherfrequency results in a higher turndown ratio. The turndown ratio at ahigher frequency is calculated by multiplying the turndown ratio at alower frequency by the square root of the higher frequency divided bythe lower frequency. In some embodiments, a frequency between 100 Hz and1000 Hz, between 140 Hz and 200 Hz, or between 400 Hz and 600 Hz is used(for example, 180 Hz, 540 Hz, or 720 Hz). In some embodiments, highfrequencies may be used. The frequencies may be greater than 1000 Hz.

To maintain a substantially constant skin depth until the Curietemperature of the temperature limited heater is reached, the heater maybe operated at a lower frequency when the heater is cold and operated ata higher frequency when the heater is hot. Line frequency heating isgenerally favorable, however, because there is less need for expensivecomponents such as power supplies, transformers, or current modulatorsthat alter frequency. Line frequency is the frequency of a generalsupply of current. Line frequency is typically 60 Hz, but may be 50 Hzor another frequency depending on the source for the supply of thecurrent. Higher frequencies may be produced using commercially availableequipment such as solid state variable frequency power supplies.Transformers that convert three-phase power to single-phase power withthree times the frequency are commercially available. For example, highvoltage three-phase power at 60 Hz may be transformed to single-phasepower at 180 Hz and at a lower voltage. Such transformers are lessexpensive and more energy efficient than solid state variable frequencypower supplies. In certain embodiments, transformers that convertthree-phase power to single-phase power are used to increase thefrequency of power supplied to the temperature limited heater.

In certain embodiments, modulated DC (for example, chopped DC, waveformmodulated DC, or cycled DC) may be used for providing electrical powerto the temperature limited heater. A DC modulator or DC chopper may becoupled to a DC power supply to provide an output of modulated directcurrent. In some embodiments, the DC power supply may include means formodulating DC. One example of a DC modulator is a DC-to-DC convertersystem. DC-to-DC converter systems are generally known in the art. DC istypically modulated or chopped into a desired waveform. Waveforms for DCmodulation include, but are not limited to, square-wave, sinusoidal,deformed sinusoidal, deformed square-wave, triangular, and other regularor irregular waveforms.

The modulated DC waveform generally defines the frequency of themodulated DC. Thus, the modulated DC waveform may be selected to providea desired modulated DC frequency. The shape and/or the rate ofmodulation (such as the rate of chopping) of the modulated DC waveformmay be varied to vary the modulated DC frequency. DC may be modulated atfrequencies that are higher than generally available AC frequencies. Forexample, modulated DC may be provided at frequencies of at least 1000Hz. Increasing the frequency of supplied current to higher valuesadvantageously increases the turndown ratio of the temperature limitedheater.

In certain embodiments, the modulated DC waveform is adjusted or alteredto vary the modulated DC frequency. The DC modulator may be able toadjust or alter the modulated DC waveform at any time during use of thetemperature limited heater and at high currents or voltages. Thus,modulated DC provided to the temperature limited heater is not limitedto a single frequency or even a small set of frequency values. Waveformselection using the DC modulator typically allows for a wide range ofmodulated DC frequencies and for discrete control of the modulated DCfrequency. Thus, the modulated DC frequency is more easily set at adistinct value whereas AC frequency is generally limited to multiples ofthe line frequency. Discrete control of the modulated DC frequencyallows for more selective control over the turndown ratio of thetemperature limited heater. Being able to selectively control theturndown ratio of the temperature limited heater allows for a broaderrange of materials to be used in designing and constructing thetemperature limited heater.

In some embodiments, the modulated DC frequency or the AC frequency isadjusted to compensate for changes in properties (for example,subsurface conditions such as temperature or pressure) of thetemperature limited heater during use. The modulated DC frequency or theAC frequency provided to the temperature limited heater is varied basedon assessed downhole conditions. For example, as the temperature of thetemperature limited heater in the wellbore increases, it may beadvantageous to increase the frequency of the current provided to theheater, thus increasing the turndown ratio of the heater. In anembodiment, the downhole temperature of the temperature limited heaterin the wellbore is assessed.

In certain embodiments, the modulated DC frequency, or the AC frequency,is varied to adjust the turndown ratio of the temperature limitedheater. The turndown ratio may be adjusted to compensate for hot spotsoccurring along a length of the temperature limited heater. For example,the turndown ratio is increased because the temperature limited heateris getting too hot in certain locations. In some embodiments, themodulated DC frequency, or the AC frequency, are varied to adjust aturndown ratio without assessing a subsurface condition.

At or near the Curie temperature of the ferromagnetic material, arelatively small change in voltage may cause a relatively large changein current to the load. The relatively small change in voltage mayproduce problems in the power supplied to the temperature limitedheater, especially at or near the Curie temperature. The problemsinclude, but are not limited to, reducing the power factor, tripping acircuit breaker, and/or blowing a fuse. In some cases, voltage changesmay be caused by a change in the load of the temperature limited heater.In certain embodiments, an electrical current supply (for example, asupply of modulated DC or AC) provides a relatively constant amount ofcurrent that does not substantially vary with changes in load of thetemperature limited heater. In an embodiment, the electrical currentsupply provides an amount of electrical current that remains within 15%,within 10%, within 5%, or within 2% of a selected constant current valuewhen a load of the temperature limited heater changes.

Temperature limited heaters may generate an inductive load. Theinductive load is due to some applied electrical current being used bythe ferromagnetic material to generate a magnetic field in addition togenerating a resistive heat output. As downhole temperature changes inthe temperature limited heater, the inductive load of the heater changesdue to changes in the ferromagnetic properties of ferromagneticmaterials in the heater with temperature. The inductive load of thetemperature limited heater may cause a phase shift between the currentand the voltage applied to the heater.

A reduction in actual power applied to the temperature limited heatermay be caused by a time lag in the current waveform (for example, thecurrent has a phase shift relative to the voltage due to an inductiveload) and/or by distortions in the current waveform (for example,distortions in the current waveform caused by introduced harmonics dueto a non-linear load). Thus, it may take more current to apply aselected amount of power due to phase shifting or waveform distortion.The ratio of actual power applied and the apparent power that would havebeen transmitted if the same current were in phase and undistorted isthe power factor. The power factor is always less than or equal to 1.The power factor is 1 when there is no phase shift or distortion in thewaveform.

Actual power applied to a heater due to a phase shift may be describedby EQN. 4:P=I×V×cos(θ);  (4)in which P is the actual power applied to a heater; I is the appliedcurrent; V is the applied voltage; and θ is the phase angle differencebetween voltage and current. Other phenomena such as waveform distortionmay contribute to further lowering of the power factor. If there is nodistortion in the waveform, then cos(θ) is equal to the power factor.

In certain embodiments, the temperature limited heater includes an innerconductor inside an outer conductor. The inner conductor and the outerconductor are radially disposed about a central axis. The inner andouter conductors may be separated by an insulation layer. In certainembodiments, the inner and outer conductors are coupled at the bottom ofthe temperature limited heater. Electrical current may flow into thetemperature limited heater through the inner conductor and returnthrough the outer conductor. One or both conductors may includeferromagnetic material.

The insulation layer may comprise an electrically insulating ceramicwith high thermal conductivity, such as magnesium oxide, aluminum oxide,silicon dioxide, beryllium oxide, boron nitride, silicon nitride, orcombinations thereof. The insulating layer may be a compacted powder(for example, compacted ceramic powder). Compaction may improve thermalconductivity and provide better insulation resistance. For lowertemperature applications, polymer insulation made from, for example,fluoropolymers, polyimides, polyamides, and/or polyethylenes, may beused. In some embodiments, the polymer insulation is made ofperfluoroalkoxy (PFA) or polyetheretherketone (PEEK™ (Victrex Ltd,England)). The insulating layer may be chosen to be substantiallyinfrared transparent to aid heat transfer from the inner conductor tothe outer conductor. In an embodiment, the insulating layer istransparent quartz sand. The insulation layer may be air or anon-reactive gas such as helium, nitrogen, or sulfur hexafluoride. Ifthe insulation layer is air or a non-reactive gas, there may beinsulating spacers designed to inhibit electrical contact between theinner conductor and the outer conductor. The insulating spacers may bemade of, for example, high purity aluminum oxide or another thermallyconducting, electrically insulating material such as silicon nitride.The insulating spacers may be a fibrous ceramic material such as Nextel™312 (3M Corporation, St. Paul, Minn., U.S.A.), mica tape, or glassfiber. Ceramic material may be made of alumina, alumina-silicate,alumina-borosilicate, silicon nitride, boron nitride, or othermaterials.

The insulation layer may be flexible and/or substantially deformationtolerant. For example, if the insulation layer is a solid or compactedmaterial that substantially fills the space between the inner and outerconductors, the temperature limited heater may be flexible and/orsubstantially deformation tolerant. Forces on the outer conductor can betransmitted through the insulation layer to the solid inner conductor,which may resist crushing. Such a temperature limited heater may bebent, dog-legged, and spiraled without causing the outer conductor andthe inner conductor to electrically short to each other. Deformationtolerance may be important if the wellbore is likely to undergosubstantial deformation during heating of the formation.

In certain embodiments, an outermost layer of the temperature limitedheater (for example, the outer conductor) is chosen for corrosionresistance, yield strength, and/or creep resistance. In one embodiment,austenitic (non-ferromagnetic) stainless steels such as 201, 304H, 347H,347HH, 316H, 310H, 347HP, NF709 (Nippon Steel Corp., Japan) stainlesssteels, or combinations thereof may be used in the outer conductor. Theoutermost layer may also include a clad conductor. For example, acorrosion resistant alloy such as 800H or 347H stainless steel may beclad for corrosion protection over a ferromagnetic carbon steel tubular.If high temperature strength is not required, the outermost layer may beconstructed from ferromagnetic metal with good corrosion resistance suchas one of the ferritic stainless steels. In one embodiment, a ferriticalloy of 82.3% by weight iron with 17.7% by weight chromium (Curietemperature of 678° C.) provides desired corrosion resistance.

The Metals Handbook, vol. 8, page 291 (American Society of Materials(ASM)) includes a graph of Curie temperature of iron-chromium alloysversus the amount of chromium in the alloys. In some temperature limitedheater embodiments, a separate support rod or tubular (made from 347Hstainless steel) is coupled to the temperature limited heater made froman iron-chromium alloy to provide yield strength and/or creepresistance. In certain embodiments, the support material and/or theferromagnetic material is selected to provide a 100,000 hourcreep-rupture strength of at least 20.7 MPa at 650° C. In someembodiments, the 100,000 hour creep-rupture strength is at least 13.8MPa at 650° C. or at least 6.9 MPa at 650° C. For example, 347H steelhas a favorable creep-rupture strength at or above 650° C. In someembodiments, the 100,000 hour creep-rupture strength ranges from 6.9 Mpato 41.3 Mpa or more for longer heaters and/or higher earth or fluidstresses.

In temperature limited heater embodiments with both an innerferromagnetic conductor and an outer ferromagnetic conductor, the skineffect current path occurs on the outside of the inner conductor and onthe inside of the outer conductor. Thus, the outside of the outerconductor may be clad with the corrosion resistant alloy, such asstainless steel, without affecting the skin effect current path on theinside of the outer conductor.

A ferromagnetic conductor with a thickness of at least the skin depth atthe Curie temperature allows a substantial decrease in resistance of theferromagnetic material as the skin depth increases sharply near theCurie temperature. In certain embodiments when the ferromagneticconductor is not clad with a highly conducting material such as copper,the thickness of the conductor may be 1.5 times the skin depth near theCurie temperature, 3 times the skin depth near the Curie temperature, oreven 10 or more times the skin depth near the Curie temperature. If theferromagnetic conductor is clad with copper, thickness of theferromagnetic conductor may be substantially the same as the skin depthnear the Curie temperature. In some embodiments, the ferromagneticconductor clad with copper has a thickness of at least three-fourths ofthe skin depth near the Curie temperature.

In certain embodiments, the temperature limited heater includes acomposite conductor with a ferromagnetic tubular and anon-ferromagnetic, high electrical conductivity core. Thenon-ferromagnetic, high electrical conductivity core reduces a requireddiameter of the conductor. For example, the conductor may be composite1.19 cm diameter conductor with a core of 0.575 cm diameter copper cladwith a 0.298 cm thickness of ferritic stainless steel or carbon steelsurrounding the core. The core or non-ferromagnetic conductor may becopper or copper alloy. The core or non-ferromagnetic conductor may alsobe made of other metals that exhibit low electrical resistivity andrelative magnetic permeabilities near 1 (for example, substantiallynon-ferromagnetic materials such as aluminum and aluminum alloys,phosphor bronze, beryllium copper, and/or brass). A composite conductorallows the electrical resistance of the temperature limited heater todecrease more steeply near the Curie temperature. As the skin depthincreases near the Curie temperature to include the copper core, theelectrical resistance decreases very sharply.

The composite conductor may increase the conductivity of the temperaturelimited heater and/or allow the heater to operate at lower voltages. Inan embodiment, the composite conductor exhibits a relatively flatresistance versus temperature profile at temperatures below a regionnear the Curie temperature of the ferromagnetic conductor of thecomposite conductor. In some embodiments, the temperature limited heaterexhibits a relatively flat resistance versus temperature profile between100° C. and 750° C. or between 300° C. and 600° C. The relatively flatresistance versus temperature profile may also be exhibited in othertemperature ranges by adjusting, for example, materials and/or theconfiguration of materials in the temperature limited heater. In certainembodiments, the relative thickness of each material in the compositeconductor is selected to produce a desired resistivity versustemperature profile for the temperature limited heater.

In certain embodiments, the relative thickness of each material in acomposite conductor is selected to produce a desired resistivity versustemperature profile for a temperature limited heater. In an embodiment,the composite conductor is an inner conductor surrounded by 0.127 cmthick magnesium oxide powder as an insulator. The outer conductor may be304H stainless steel with a wall thickness of 0.127 cm. The outsidediameter of the heater may be about 1.65 cm.

A composite conductor (for example, a composite inner conductor or acomposite outer conductor) may be manufactured by methods including, butnot limited to, coextrusion, roll forming, tight fit tubing (forexample, cooling the inner member and heating the outer member, theninserting the inner member in the outer member, followed by a drawingoperation and/or allowing the system to cool), explosive orelectromagnetic cladding, arc overlay welding, longitudinal stripwelding, plasma powder welding, billet coextrusion, electroplating,drawing, sputtering, plasma deposition, coextrusion casting, magneticforming, molten cylinder casting (of inner core material inside theouter or vice versa), insertion followed by welding or high temperaturebraising, shielded active gas welding (SAG), and/or insertion of aninner pipe in an outer pipe followed by mechanical expansion of theinner pipe by hydroforming or use of a pig to expand and swage the innerpipe against the outer pipe. In some embodiments, a ferromagneticconductor is braided over a non-ferromagnetic conductor. In certainembodiments, composite conductors are formed using methods similar tothose used for cladding (for example, cladding copper to steel). Ametallurgical bond between copper cladding and base ferromagneticmaterial may be advantageous. Composite conductors produced by acoextrusion process that forms a good metallurgical bond (for example, agood bond between copper and 446 stainless steel) may be provided byAnomet Products, Inc. (Shrewsbury, Mass., U.S.A.).

FIGS. 21-42 depict various embodiments of temperature limited heaters.One or more features of an embodiment of the temperature limited heaterdepicted in any of these figures may be combined with one or morefeatures of other embodiments of temperature limited heaters depicted inthese figures. In certain embodiments described herein, temperaturelimited heaters are dimensioned to operate at a frequency of 60 Hz AC.It is to be understood that dimensions of the temperature limited heatermay be adjusted from those described herein to operate in a similarmanner at other AC frequencies or with modulated DC current.

FIG. 21 depicts a cross-sectional representation of an embodiment of thetemperature limited heater with an outer conductor having aferromagnetic section and a non-ferromagnetic section. FIGS. 22 and 23depict transverse cross-sectional views of the embodiment shown in FIG.21. In one embodiment, ferromagnetic section 486 is used to provide heatto hydrocarbon layers in the formation. Non-ferromagnetic section 488 isused in the overburden of the formation. Non-ferromagnetic section 488provides little or no heat to the overburden, thus inhibiting heatlosses in the overburden and improving heater efficiency. Ferromagneticsection 486 includes a ferromagnetic material such as 409 stainlesssteel or 410 stainless steel. Ferromagnetic section 486 has a thicknessof 0.3 cm. Non-ferromagnetic section 488 is copper with a thickness of0.3 cm. Inner conductor 490 is copper. Inner conductor 490 has adiameter of 0.9 cm. Electrical insulator 500 is silicon nitride, boronnitride, magnesium oxide powder, or another suitable insulator material.Electrical insulator 500 has a thickness of 0.1 cm to 0.3 cm.

FIG. 24 depicts a cross-sectional representation of an embodiment of atemperature limited heater with an outer conductor having aferromagnetic section and a non-ferromagnetic section placed inside asheath. FIGS. 25, 26, and 27 depict transverse cross-sectional views ofthe embodiment shown in FIG. 24. Ferromagnetic section 486 is 410stainless steel with a thickness of 0.6 cm. Non-ferromagnetic section488 is copper with a thickness of 0.6 cm. Inner conductor 490 is copperwith a diameter of 0.9 cm. Outer conductor 502 includes ferromagneticmaterial. Outer conductor 502 provides some heat in the overburdensection of the heater. Providing some heat in the overburden inhibitscondensation or refluxing of fluids in the overburden. Outer conductor502 is 409, 410, or 446 stainless steel with an outer diameter of 3.0 cmand a thickness of 0.6 cm. Electrical insulator 500 includes compactedmagnesium oxide powder with a thickness of 0.3 cm. In some embodiments,electrical insulator 500 includes silicon nitride, boron nitride, orhexagonal type boron nitride. Conductive section 504 may couple innerconductor 490 with ferromagnetic section 486 and/or outer conductor 502.

FIG. 28A and FIG. 28B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic innerconductor. Inner conductor 490 is a 1″ Schedule XXS 446 stainless steelpipe. In some embodiments, inner conductor 490 includes 409 stainlesssteel, 410 stainless steel, Invar 36, alloy 42-6, alloy 52, or otherferromagnetic materials. Inner conductor 490 has a diameter of 2.5 cm.Electrical insulator 500 includes compacted silicon nitride, boronnitride, or magnesium oxide powders; or polymers, Nextel ceramic fiber,mica, or glass fibers. Outer conductor 502 is copper or any othernon-ferromagnetic material, such as but not limited to copper alloys,aluminum and/or aluminum alloys. Outer conductor 502 is coupled tojacket 506. Jacket 506 is 304H, 316H, or 347H stainless steel. In thisembodiment, a majority of the heat is produced in inner conductor 490.

FIG. 29A and FIG. 29B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic innerconductor and a non-ferromagnetic core. Inner conductor 490 may be madeof 446 stainless steel, 409 stainless steel, 410 stainless steel, carbonsteel, Armco ingot iron, iron-cobalt alloys, or other ferromagneticmaterials. Core 508 may be tightly bonded inside inner conductor 490.Core 508 is copper or other non-ferromagnetic material. In certainembodiments, core 508 is inserted as a tight fit inside inner conductor490 before a drawing operation. In some embodiments, core 508 and innerconductor 490 are coextrusion bonded. Outer conductor 502 is 347Hstainless steel. A drawing or rolling operation to compact electricalinsulator 500 (for example, compacted silicon nitride, boron nitride, ormagnesium oxide powder) may ensure good electrical contact between innerconductor 490 and core 508. In this embodiment, heat is producedprimarily in inner conductor 490 until the Curie temperature isapproached. Resistance then decreases sharply as current penetrates core508.

FIG. 30A and FIG. 30B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor. Inner conductor 490 is nickel-clad copper. Electricalinsulator 500 is silicon nitride, boron nitride, or magnesium oxide.Outer conductor 502 is a 1″ Schedule XXS carbon steel pipe. In thisembodiment, heat is produced primarily in outer conductor 502, resultingin a small temperature differential across electrical insulator 500.

FIG. 31A and FIG. 31B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor that is clad with a corrosion resistant alloy. Inner conductor490 is copper. Outer conductor 502 is a 1″ Schedule XXS carbon steelpipe. Outer conductor 502 is coupled to jacket 506. Jacket 506 is madeof corrosion resistant material (for example, 347H stainless steel).Jacket 506 provides protection from corrosive fluids in the wellbore(for example, sulfidizing and carburizing gases). Heat is producedprimarily in outer conductor 502, resulting in a small temperaturedifferential across electrical insulator 500.

FIG. 32A and FIG. 32B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor. The outer conductor is clad with a conductive layer and acorrosion resistant alloy. Inner conductor 490 is copper. Electricalinsulator 500 is silicon nitride, boron nitride, or magnesium oxide.Outer conductor 502 is a 1″ Schedule 80 446 stainless steel pipe. Outerconductor 502 is coupled to jacket 506. Jacket 506 is made fromcorrosion resistant material such as 347H stainless steel. In anembodiment, conductive layer 510 is placed between outer conductor 502and jacket 506. Conductive layer 510 is a copper layer. Heat is producedprimarily in outer conductor 502, resulting in a small temperaturedifferential across electrical insulator 500. Conductive layer 510allows a sharp decrease in the resistance of outer conductor 502 as theouter conductor approaches the Curie temperature. Jacket 506 providesprotection from corrosive fluids in the wellbore.

In some embodiments, the conductor (for example, an inner conductor, anouter conductor, or a ferromagnetic conductor) is the compositeconductor that includes two or more different materials. In certainembodiments, the composite conductor includes two or more ferromagneticmaterials. In some embodiments, the composite ferromagnetic conductorincludes two or more radially disposed materials. In certainembodiments, the composite conductor includes a ferromagnetic conductorand a non-ferromagnetic conductor. In some embodiments, the compositeconductor includes the ferromagnetic conductor placed over anon-ferromagnetic core. Two or more materials may be used to obtain arelatively flat electrical resistivity versus temperature profile in atemperature region below the Curie temperature and/or a sharp decrease(a high turndown ratio) in the electrical resistivity at or near theCurie temperature. In some cases, two or more materials are used toprovide more than one Curie temperature for the temperature limitedheater.

The composite electrical conductor may be used as the conductor in anyelectrical heater embodiment described herein. For example, thecomposite conductor may be used as the conductor in aconductor-in-conduit heater or an insulated conductor heater. In certainembodiments, the composite conductor may be coupled to a support membersuch as a support conductor. The support member may be used to providesupport to the composite conductor so that the composite conductor isnot relied upon for strength at or near the Curie temperature. Thesupport member may be useful for heaters of lengths of at least 100 m.The support member may be a non-ferromagnetic member that has good hightemperature creep strength. Examples of materials that are used for asupport member include, but are not limited to, Haynes® 625 alloy andHaynes® HR120® alloy (Haynes International, Kokomo, Ind., U.S.A.),NF709, Incoloy® 800H alloy and 347HP alloy (Allegheny Ludlum Corp.,Pittsburgh, Pa., U.S.A.). In some embodiments, materials in a compositeconductor are directly coupled (for example, brazed, metallurgicallybonded, or swaged) to each other and/or the support member. Using asupport member may reduce the need for the ferromagnetic member toprovide support for the temperature limited heater, especially at ornear the Curie temperature. Thus, the temperature limited heater may bedesigned with more flexibility in the selection of ferromagneticmaterials.

FIG. 33 depicts a cross-sectional representation of an embodiment of thecomposite conductor with the support member. Core 508 is surrounded byferromagnetic conductor 512 and support member 514. In some embodiments,core 508, ferromagnetic conductor 512, and support member 514 aredirectly coupled (for example, brazed together or metallurgically bondedtogether). In one embodiment, core 508 is copper, ferromagneticconductor 512 is 446 stainless steel, and support member 514 is 347Halloy. In certain embodiments, support member 514 is a Schedule 80 pipe.Support member 514 surrounds the composite conductor havingferromagnetic conductor 512 and core 508. Ferromagnetic conductor 512and core 508 may be joined to form the composite conductor by, forexample, a coextrusion process. For example, the composite conductor isa 1.9 cm outside diameter 446 stainless steel ferromagnetic conductorsurrounding a 0.95 cm diameter copper core.

In certain embodiments, the diameter of core 508 is adjusted relative toa constant outside diameter of ferromagnetic conductor 512 to adjust theturndown ratio of the temperature limited heater. For example, thediameter of core 508 may be increased to 1.14 cm while maintaining theoutside diameter of ferromagnetic conductor 512 at 1.9 cm to increasethe turndown ratio of the heater.

In some embodiments, conductors (for example, core 508 and ferromagneticconductor 512) in the composite conductor are separated by supportmember 514. FIG. 34 depicts a cross-sectional representation of anembodiment of the composite conductor with support member 514 separatingthe conductors. In one embodiment, core 508 is copper with a diameter of0.95 cm, support member 514 is 347H alloy with an outside diameter of1.9 cm, and ferromagnetic conductor 512 is 446 stainless steel with anoutside diameter of 2.7 cm. The support member depicted in FIG. 34 has alower creep strength relative to the support members depicted in FIG.33.

In certain embodiments, support member 514 is located inside thecomposite conductor. FIG. 35 depicts a cross-sectional representation ofan embodiment of the composite conductor surrounding support member 514.Support member 514 is made of 347H alloy. Inner conductor 490 is copper.Ferromagnetic conductor 512 is 446 stainless ste In one embodiment,support member 514 is 1.25 cm diameter 347H alloy, inner conductor 490is 1.9 cm outside diameter copper, and ferromagnetic conductor 512 is2.7 cm outside diameter 446 stainless steel. The turndown ratio ishigher than the turndown ratio for the embodiments depicted in FIGS. 33,34, and 36 for the same outside diameter, but the creep strength islower.

In some embodiments, the thickness of inner conductor 490, which iscopper, is reduced and the thickness of support member 514 is increasedto increase the creep strength at the expense of reduced turndown ratio.For example, the diameter of support member 514 is increased to 1.6 cmwhile maintaining the outside diameter of inner conductor 490 at 1.9 cmto reduce the thickness of the conduit. This reduction in thickness ofinner conductor 490 results in a decreased turndown ratio relative tothe thicker inner conductor embodiment but an increased creep strength.

In one embodiment, support member 514 is a conduit (or pipe) insideinner conductor 490 and ferromagnetic conductor 512. FIG. 36 depicts across-sectional representation of an embodiment of the compositeconductor surrounding support member 514. In one embodiment, supportmember 514 is 347H alloy with a 0.63 cm diameter center hole. In someembodiments, support member 514 is a preformed conduit. In certainembodiments, support member 514 is formed by having a dissolvablematerial (for example, copper dissolvable by nitric acid) located insidethe support member during formation of the composite conductor. Thedissolvable material is dissolved to form the hole after the conductoris assembled. In an embodiment, support member 514 is 347H alloy with aninside diameter of 0.63 cm and an outside diameter of 1.6 cm, innerconductor 490 is copper with an outside diameter of 1.8 cm, andferromagnetic conductor 512 is 446 stainless steel with an outsidediameter of 2.7 cm.

In certain embodiments, the composite electrical conductor is used asthe conductor in the conductor-in-conduit heater. For example, thecomposite electrical conductor may be used as conductor 516 in FIG. 37

FIG. 37 depicts a cross-sectional representation of an embodiment of theconductor-in-conduit heater. Conductor 516 is disposed in conduit 518.Conductor 516 is a rod or conduit of electrically conductive material.Low resistance sections 520 are present at both ends of conductor 516 togenerate less heating in these sections. Low resistance section 520 isformed by having a greater cross-sectional area of conductor 516 in thatsection, or the sections are made of material having less resistance. Incertain embodiments, low resistance section 520 includes a lowresistance conductor coupled to conductor 516.

Conduit 518 is made of an electrically conductive material. Conduit 518is disposed in opening 522 in hydrocarbon layer 460. Opening 522 has adiameter that accommodates conduit 518.

Conductor 516 may be centered in conduit 518 by centralizers 524.Centralizers 524 electrically isolate conductor 516 from conduit 518.Centralizers 524 inhibit movement and properly locate conductor 516 inconduit 518. Centralizers 524 are made of ceramic material or acombination of ceramic and metallic materials. Centralizers 524 inhibitdeformation of conductor 516 in conduit 518. Centralizers 524 aretouching or spaced at intervals between approximately 0.1 m (meters) andapproximately 3 m or more along conductor 516.

A second low resistance section 520 of conductor 516 may coupleconductor 516 to wellhead 450, as depicted in FIG. 37. Electricalcurrent may be applied to conductor 516 from power cable 526 through lowresistance section 520 of conductor 516. Electrical current passes fromconductor 516 through sliding connector 528 to conduit 518. Conduit 518may be electrically insulated from overburden casing 530 and fromwellhead 450 to return electrical current to power cable 526. Heat maybe generated in conductor 516 and conduit 518. The generated heat mayradiate in conduit 518 and opening 522 to heat at least a portion ofhydrocarbon layer 460.

Overburden casing 530 may be disposed in overburden 458. Overburdencasing 530 is, in some embodiments, surrounded by materials (forexample, reinforcing material and/or cement) that inhibit heating ofoverburden 458. Low resistance section 520 of conductor 516 may beplaced in overburden casing 530. Low resistance section 520 of conductor516 is made of, for example, carbon steel. Low resistance section 520 ofconductor 516 may be centralized in overburden casing 530 usingcentralizers 524. Centralizers 524 are spaced at intervals ofapproximately 6 m to approximately 12 m or, for example, approximately 9m along low resistance section 520 of conductor 516. In a heaterembodiment, low resistance section 520 of conductor 516 is coupled toconductor 516 by one or more welds. In other heater embodiments, lowresistance sections are threaded, threaded and welded, or otherwisecoupled to the conductor. Low resistance section 520 generates little orno heat in overburden casing 530. Packing 532 may be placed betweenoverburden casing 530 and opening 522. Packing 532 may be used as a capat the junction of overburden 458 and hydrocarbon layer 460 to allowfilling of materials in the annulus between overburden casing 530 andopening 522. In some embodiments, packing 532 inhibits fluid fromflowing from opening 522 to surface 534.

FIG. 38 depicts a cross-sectional representation of an embodiment of aremovable conductor-in-conduit heat source. Conduit 518 may be placed inopening 522 through overburden 458 such that a gap remains between theconduit and overburden casing 530. Fluids may be removed from opening522 through the gap between conduit 518 and overburden casing 530.Fluids may be removed from the gap through conduit 536. Conduit 518 andcomponents of the heat source included in the conduit that are coupledto wellhead 450 may be removed from opening 522 as a single unit. Theheat source may be removed as a single unit to be repaired, replaced,and/or used in another portion of the formation.

For a temperature limited heater in which the ferromagnetic conductorprovides a majority of the resistive heat output below the Curietemperature, a majority of the current flows through material withhighly non-linear functions of magnetic field (H) versus magneticinduction (B). These non-linear fluctions may cause strong inductiveeffects and distortion that lead to decreased power factor in thetemperature limited heater at temperatures below the Curie temperature.These effects may render the electrical power supply to the temperaturelimited heater difficult to control and may result in additional currentflow through surface and/or overburden power supply conductors.Expensive and/or difficult to implement control systems such as variablecapacitors or modulated power supplies may be used to compensate forthese effects and to control temperature limited heaters where themajority of the resistive heat output is provided by current flowthrough the ferromagnetic material.

In certain temperature limited heater embodiments, the ferromagneticconductor confines a majority of the flow of electrical current to anelectrical conductor coupled to the ferromagnetic conductor when thetemperature limited heater is below or near the Curie temperature of theferromagnetic conductor. The electrical conductor may be a sheath,jacket, support member, corrosion resistant member, or otherelectrically resistive member. In some embodiments, the ferromagneticconductor confines a majority of the flow of electrical current to theelectrical conductor positioned between an outermost layer and theferromagnetic conductor. The ferromagnetic conductor is located in thecross section of the temperature limited heater such that the magneticproperties of the ferromagnetic conductor at or below the Curietemperature of the ferromagnetic conductor confine the majority of theflow of electrical current to the electrical conductor. The majority ofthe flow of electrical current is confined to the electrical conductordue to the skin effect of the ferromagnetic conductor. Thus, themajority of the current is flowing through material with substantiallylinear resistive properties throughout most of the operating range ofthe heater.

In certain embodiments, the ferromagnetic conductor and the electricalconductor are located in the cross section of the temperature limitedheater so that the skin effect of the ferromagnetic material limits thepenetration depth of electrical current in the electrical conductor andthe ferromagnetic conductor at temperatures below the Curie temperatureof the ferromagnetic conductor. Thus, the electrical conductor providesa majority of the electrically resistive heat output of the temperaturelimited heater at temperatures up to a temperature at or near the Curietemperature of the ferromagnetic conductor. In certain embodiments, thedimensions of the electrical conductor may be chosen to provide desiredheat output characteristics.

Because the majority of the current flows through the electricalconductor below the Curie temperature, the temperature limited heaterhas a resistance versus temperature profile that at least partiallyreflects the resistance versus temperature profile of the material inthe electrical conductor. Thus, the resistance versus temperatureprofile of the temperature limited heater is substantially linear belowthe Curie temperature of the ferromagnetic conductor if the material inthe electrical conductor has a substantially linear resistance versustemperature profile. For example, the temperature limited heater inwhich the majority of the current flows in the electrical conductorbelow the Curie temperature may have a resistance versus temperatureprofile similar to the profile shown in FIG. 162. The resistance of thetemperature limited heater has little or no dependence on the currentflowing through the heater until the temperature nears the Curietemperature. The majority of the current flows in the electricalconductor rather than the ferromagnetic conductor below the Curietemperature.

Resistance versus temperature profiles for temperature limited heatersin which the majority of the current flows in the electrical conductoralso tend to exhibit sharper reductions in resistance near or at theCurie temperature of the ferromagnetic conductor. For example, thereduction in resistance shown in FIG. 162 is sharper than the reductionin resistance shown in FIG. 148. The sharper reductions in resistancenear or at the Curie temperature are easier to control than more gradualresistance reductions near the Curie temperature.

In certain embodiments, the material and/or the dimensions of thematerial in the electrical conductor are selected so that thetemperature limited heater has a desired resistance versus temperatureprofile below the Curie temperature of the ferromagnetic conductor.

Temperature limited heaters in which the majority of the current flowsin the electrical conductor rather than the ferromagnetic conductorbelow the Curie temperature are easier to predict and/or control.Behavior of temperature limited heaters in which the majority of thecurrent flows in the electrical conductor rather than the ferromagneticconductor below the Curie temperature may be predicted by, for example,its resistance versus temperature profile and/or its power factor versustemperature profile. Resistance versus temperature profiles and/or powerfactor versus temperature profiles may be assessed or predicted by, forexample, experimental measurements that assess the behavior of thetemperature limited heater, analytical equations that assess or predictthe behavior of the temperature limited heater, and/or simulations thatassess or predict the behavior of the temperature limited heater.

In certain embodiments, assessed or predicted behavior of thetemperature limited heater is used to control the temperature limitedheater. The temperature limited heater may be controlled based onmeasurements (assessments) of the resistance and/or the power factorduring operation of the heater. In some embodiments, the power, orcurrent, supplied to the temperature limited heater is controlled basedon assessment of the resistance and/or the power factor of the heaterduring operation of the heater and the comparison of this assessmentversus the predicted behavior of the heater. In certain embodiments, thetemperature limited heater is controlled without measurement of thetemperature of the heater or a temperature near the heater. Controllingthe temperature limited heater without temperature measurementeliminates operating costs associated with downhole temperaturemeasurement. Controlling the temperature limited heater based onassessment of the resistance and/or the power factor of the heater alsoreduces the time for making adjustments in the power or current suppliedto the heater compared to controlling the heater based on measuredtemperature.

As the temperature of the temperature limited heater approaches orexceeds the Curie temperature of the ferromagnetic conductor, reductionin the ferromagnetic properties of the ferromagnetic conductor allowselectrical current to flow through a greater portion of the electricallyconducting cross section of the temperature limited heater. Thus, theelectrical resistance of the temperature limited heater is reduced andthe temperature limited heater automatically provides reduced heatoutput at or near the Curie temperature of the ferromagnetic conductor.In certain embodiments, a highly electrically conductive member iscoupled to the ferromagnetic conductor and the electrical conductor toreduce the electrical resistance of the temperature limited heater at orabove the Curie temperature of the ferromagnetic conductor. The highlyelectrically conductive member may be an inner conductor, a core, oranother conductive member of copper, aluminum, nickel, or alloysthereof. The ferromagnetic conductor that confines the majority of theflow of electrical current to the electrical conductor at temperaturesbelow the Curie temperature may have a relatively small cross sectioncompared to the ferromagnetic conductor in temperature limited heatersthat use the ferromagnetic conductor to provide the majority ofresistive heat output up to or near the Curie temperature. A temperaturelimited heater that uses the electrical conductor to provide a majorityof the resistive heat output below the Curie temperature has lowmagnetic inductance at temperatures below the Curie temperature becauseless current is flowing through the ferromagnetic conductor as comparedto the temperature limited heater where the majority of the resistiveheat output below the Curie temperature is provided by the ferromagneticmaterial. Magnetic field (H) at radius (r) of the ferromagneticconductor is proportional to the current (I) flowing through theferromagnetic conductor and the core divided by the radius, or:H∝I/r.  (5)Since only a portion of the current flows through the ferromagneticconductor for a temperature limited heater that uses the outer conductorto provide a majority of the resistive heat output below the Curietemperature, the magnetic field of the temperature limited heater may besignificantly smaller than the magnetic field of the temperature limitedheater where the majority of the current flows through the ferromagneticmaterial. The relative magnetic permeability (μ) may be large for smallmagnetic fields.

The skin depth (δ) of the ferromagnetic conductor is inverselyproportional to the square root of the relative magnetic permeability(μ):δ∝(1/μ)^(1/2).  (6)Increasing the relative magnetic permeability decreases the skin depthof the ferromagnetic conductor. However, because only a portion of thecurrent flows through the ferromagnetic conductor for temperatures belowthe Curie temperature, the radius (or thickness) of the ferromagneticconductor may be decreased for ferromagnetic materials with largerelative magnetic permeabilities to compensate for the decreased skindepth while still allowing the skin effect to limit the penetrationdepth of the electrical current to the electrical conductor attemperatures below the Curie temperature of the ferromagnetic conductor.The radius (thickness) of the ferromagnetic conductor may be between 0.3mm and 8 mm, between 0.3 mm and 2 mm, or between 2 mm and 4 mm dependingon the relative magnetic permeability of the ferromagnetic conductor.Decreasing the thickness of the ferromagnetic conductor decreases costsof manufacturing the temperature limited heater, as the cost offerromagnetic material tends to be a significant portion of the cost ofthe temperature limited heater. Increasing the relative magneticpermeability of the ferromagnetic conductor provides a higher turndownratio and a sharper decrease in electrical resistance for thetemperature limited heater at or near the Curie temperature of theferromagnetic conductor.

Ferromagnetic materials (such as purified iron or iron-cobalt alloys)with high relative magnetic permeabilities (for example, at least 200,at least 1000, at least 1×10⁴, or at least 1×10⁵) and/or high Curietemperatures (for example, at least 600° C., at least 700° C., or atleast 800° C.) tend to have less corrosion resistance and/or lessmechanical strength at high temperatures. The electrical conductor mayprovide corrosion resistance and/or high mechanical strength at hightemperatures for the temperature limited heater. Thus, the ferromagneticconductor may be chosen primarily for its ferromagnetic properties.

Confining the majority of the flow of electrical current to theelectrical conductor below the Curie temperature of the ferromagneticconductor reduces variations in the power factor. Because only a portionof the electrical current flows through the ferromagnetic conductorbelow the Curie temperature, the non-linear ferromagnetic properties ofthe ferromagnetic conductor have little or no effect on the power factorof the temperature limited heater, except at or near the Curietemperature. Even at or near the Curie temperature, the effect on thepower factor is reduced compared to temperature limited heaters in whichthe ferromagnetic conductor provides a majority of the resistive heatoutput below the Curie temperature. Thus, there is less or no need forexternal compensation (for example, variable capacitors or waveformmodification) to adjust for changes in the inductive load of thetemperature limited heater to maintain a relatively high power factor.

In certain embodiments, the temperature limited heater, which confinesthe majority of the flow of electrical current to the electricalconductor below the Curie temperature of the ferromagnetic conductor,maintains the power factor above 0.85, above 0.9, or above 0.95 duringuse of the heater. Any reduction in the power factor occurs only insections of the temperature limited heater at temperatures near theCurie temperature. Most sections of the temperature limited heater aretypically not at or near the Curie temperature during use. Thesesections have a high power factor that approaches 1.0. The power factorfor the entire temperature limited heater is maintained above 0.85,above 0.9, or above 0.95 during use of the heater even if some sectionsof the heater have power factors below 0.85.

Maintaining high power factors allows for less expensive power suppliesand/or control devices such as solid state power supplies or SCRs(silicon controlled rectifiers). These devices may fail to operateproperly if the power factor varies by too large an amount because ofinductive loads. With the power factors maintained at high values;however, these devices may be used to provide power to the temperaturelimited heater. Solid state power supplies have the advantage ofallowing fine tuning and controlled adjustment of the power supplied tothe temperature limited heater.

In some embodiments, transformers are used to provide power to thetemperature limited heater. Multiple voltage taps may be made into thetransformer to provide power to the temperature limited heater. Multiplevoltage taps allows the current supplied to switch back and forthbetween the multiple voltages. This maintains the current within a rangebound by the multiple voltage taps.

The highly electrically conductive member, or inner conductor, increasesthe turndown ratio of the temperature limited heater. In certainembodiments, thickness of the highly electrically conductive member isincreased to increase the turndown ratio of the temperature limitedheater. In some embodiments, the thickness of the electrical conductoris reduced to increase the turndown ratio of the temperature limitedheater. In certain embodiments, the turndown ratio of the temperaturelimited heater is between 1.1 and 10, between 2 and 8, or between 3 and6 (for example, the turndown ratio is at least 1.1, at least 2, or atleast 3).

FIG. 39 depicts an embodiment of a temperature limited heater in whichthe support member provides a majority of the heat output below theCurie temperature of the ferromagnetic conductor. Core 508 is an innerconductor of the temperature limited heater. In certain embodiments,core 508 is a highly electrically conductive material such as copper oraluminum. In some embodiments, core 508 is a copper alloy that providesmechanical strength and good electrically conductivity such as adispersion strengthened copper. In one embodiment, core 508 is Glidcop®(SCM Metal Products, Inc., Research Triangle Park, N.C., U.S.A.).Ferromagnetic conductor 512 is a thin layer of ferromagnetic materialbetween electrical conductor 538 and core 508. In certain embodiments,electrical conductor 538 is also support member 514. In certainembodiments, ferromagnetic conductor 512 is iron or an iron alloy. Insome embodiments, ferromagnetic conductor 512 includes ferromagneticmaterial with a high relative magnetic permeability. For example,ferromagnetic conductor 512 may be purified iron such as Armco ingotiron (AK Steel Ltd., United Kingdom). Iron with some impuritiestypically has a relative magnetic permeability on the order of 400.Purifying the iron by annealing the iron in hydrogen gas (H₂) at 1450°C. increases the relative magnetic permeability of the iron. Increasingthe relative magnetic permeability of ferromagnetic conductor 512 allowsthe thickness of the ferromagnetic conductor to be reduced. For example,the thickness of unpurified iron may be approximately 4.5 mm while thethickness of the purified iron is approximately 0.76 mm.

In certain embodiments, electrical conductor 538 provides support forferromagnetic conductor 512 and the temperature limited heater.Electrical conductor 538 may be made of a material that provides goodmechanical strength at temperatures near or above the Curie temperatureof ferromagnetic conductor 512. In certain embodiments, electricalconductor 538 is a corrosion resistant member. Electrical conductor 538(support member 514) may provide support for ferromagnetic conductor 512and corrosion resistance. Electrical conductor 538 is made from amaterial that provides desired electrically resistive heat output attemperatures up to and/or above the Curie temperature of ferromagneticconductor 512.

In an embodiment, electrical conductor 538 is 347H stainless steel. Insome embodiments, electrical conductor 538 is another electricallyconductive, good mechanical strength, corrosion resistant material. Forexample, electrical conductor 538 may be 304H, 316H, 347HH, NF709,Incoloy® 800H alloy (Inco Alloys International, Huntington, W. Va.,U.S.A.), Haynes® HR120® alloy, or Inconel® 617 alloy.

In some embodiments, electrical conductor 538 (support member 514)includes different alloys in different portions of the temperaturelimited heater. For example, a lower portion of electrical conductor 538(support member 514) is 347H stainless steel and an upper portion of theelectrical conductor (support member) is NF709. In certain embodiments,different alloys are used in different portions of the electricalconductor (support member) to increase the mechanical strength of theelectrical conductor (support member) while maintaining desired heatingproperties for the temperature limited heater.

In some embodiments, ferromagnetic conductor 512 includes differentferromagnetic conductors in different portions of the temperaturelimited heater. Different ferromagnetic conductors may be used indifferent portions of the temperature limited heater to vary the Curietemperature and, thus, the maximum operating temperature in thedifferent portions. In some embodiments, the Curie temperature in anupper portion of the temperature limited heater is lower than the Curietemperature in a lower portion of the heater. The lower Curietemperature in the upper portion increases the creep-rupture strengthlifetime in the upper portion of the heater.

In the embodiment depicted in FIG. 39, ferromagnetic conductor 512,electrical conductor 538, and core 508 are dimensioned so that the skindepth of the ferromagnetic conductor limits the penetration depth of themajority of the flow of electrical current to the support member whenthe temperature is below the Curie temperature of the ferromagneticconductor. Thus, electrical conductor 538 provides a majority of theelectrically resistive heat output of the temperature limited heater attemperatures up to a temperature at or near the Curie temperature offerromagnetic conductor 512. In certain embodiments, the temperaturelimited heater depicted in FIG. 39 is smaller (for example, an outsidediameter of 3 cm, 2.9 cm, 2.5 cm, or less) than other temperaturelimited heaters that do not use electrical conductor 538 to provide themajority of electrically resistive heat output. The temperature limitedheater depicted in FIG. 39 may be smaller because ferromagneticconductor 512 is thin as compared to the size of the ferromagneticconductor needed for a temperature limited heater in which the majorityof the resistive heat output is provided by the ferromagnetic conductor.

In some embodiments, the support member and the corrosion resistantmember are different members in the temperature limited heater. FIGS. 40and 41 depict embodiments of temperature limited heaters in which thejacket provides a majority of the heat output below the Curietemperature of the ferromagnetic conductor. In these embodiments,electrical conductor 538 is jacket 506. Electrical conductor 538,ferromagnetic conductor 512, support member 514, and core 508 (in FIG.40) or inner conductor 490 (in FIG. 41) are dimensioned so that the skindepth of the ferromagnetic conductor limits the penetration depth of themajority of the flow of electrical current to the thickness of thejacket. In certain embodiments, electrical conductor 538 is a materialthat is corrosion resistant and provides electrically resistive heatoutput below the Curie temperature of ferromagnetic conductor 512. Forexample, electrical conductor 538 is 825 stainless steel or 347Hstainless steel. In some embodiments, electrical conductor 538 has asmall thickness (for example, on the order of 0.5 mm).

In FIG. 40, core 508 is highly electrically conductive material such ascopper or aluminum. Support member 514 is 347H stainless steel oranother material with good mechanical strength at or near the Curietemperature of ferromagnetic conductor 512.

In FIG. 41, support member 514 is the core of the temperature limitedheater and is 347H stainless steel or another material with goodmechanical strength at or near the Curie temperature of ferromagneticconductor 512. Inner conductor 490 is highly electrically conductivematerial such as copper or aluminum.

In certain embodiments, the materials and design of the temperaturelimited heater are chosen to allow use of the heater at hightemperatures (for example, above 850° C.). FIG. 42 depicts a hightemperature embodiment of the temperature limited heater. The heaterdepicted in FIG. 42 operates as a conductor-in-conduit heater with themajority of heat being generated in conduit 518. Theconductor-in-conduim heater may provide a higher heat output because themajority of heat is generated in conduit 518 rather than conductor 516.Having the heat generated in conduit 518 reduces heat losses associatedwith transferring heat between the conduit and conductor 516.

Core 508 and conductive layer 510 are copper. In some embodiments, core508 and conductive layer 510 are nickel if the operating temperatures isto be near or above the melting point of copper. Support members 514 areelectrically conductive materials with good mechanical strength at hightemperatures. Materials for support members 514 that withstand at leasta maximum temperature of about 870° C. may be, but are not limited to,MO-RE® alloys (Duraloy Technologies, Inc. (Scottdale, Pa., U.S.A.)),CF8C+ (Metaltek Intl. (Waukesha, Wis., U.S.A.)), or Inconel® 617 alloy.Materials for support members 514 that withstand at least a maximumtemperature of about 980° C. include, but are not limited to, Incoloy®Alloy MA 956. Support member 514 in conduit 518 provides mechanicsupport for the conduit. Support member 514 in conductor 516 providesmechanical support for core 508.

Electrical conductor 538 is a thin corrosion resistant material. Incertain embodiments, electrical conductor 538 is 347H, 617, 625, or 800Hstainless steel. Ferromagnetic conductor 512 is a high Curie temperatureferromagnetic material such as iron-cobalt alloy (for example, a 15% byweight cobalt, iron-cobalt alloy).

In certain embodiments, electrical conductor 538 provides the majorityof heat output of the temperature limited heater at temperatures up to atemperature at or near the Curie temperature of ferromagnetic conductor512. Conductive layer 510 increases the turndown ratio of thetemperature limited heater.

For long vertical temperature limited heaters (for example, heaters atleast 300 m, at least 500 m, or at least 1 km in length), the hangingstress becomes important in the selection of materials for thetemperature limited heater. Without the proper selection of material,the support member may not have sufficient mechanical strength (forexample, creep-rupture strength) to support the weight of thetemperature limited heater at the operating temperatures of the heater.FIG. 43 depicts hanging stress (ksi (kilopounds per square inch)) versusoutside diameter (in.) for the temperature limited heater shown in FIG.39 with 347H as the support member. The hanging stress was assessed withthe support member outside a 0.5″ copper core and a 0.75″ outsidediameter carbon steel ferromagnetic conductor. This assessment assumesthe support member bears the entire load of the heater and that theheater length is 1000 ft. (about 305 m). As shown in FIG. 43, increasingthe thickness of the support member decreases the hanging stress on thesupport member. Decreasing the hanging stress on the support memberallows the temperature limited heater to operate at higher temperatures.

In certain embodiments, materials for the support member are varied toincrease the maximum allowable hanging stress at operating temperaturesof the temperature limited heater and, thus, increase the maximumoperating temperature of the temperature limited heater. Altering thematerials of the support member affects the heat output of thetemperature limited heater below the Curie temperature because changingthe materials changes the resistance versus temperature profile of thesupport member. In certain embodiments, the support member is made ofmore than one material along the length of the heater so that thetemperature limited heater maintains desired operating properties (forexample, resistance versus temperature profile below the Curietemperature) as much as possible while providing sufficient mechanicalproperties to support the heater.

FIG. 44 depicts hanging stress (ksi) versus temperature (° F.) forseveral materials and varying outside diameters for the temperaturelimited heaters. Curve 540 is for 347H stainless steel. Curve 542 is forIncoloy® alloy 800H. Curv 544 is for Haynes® HR120® alloy. Curve 546 isfor NF709. Each of the curves includes four points that representvarious outside diameters of the support member. The point with thehighest stress for each curve corresponds to outside diameter of 1.05″.The point with the second highest stress for each curve corresponds tooutside diameter of 1.15″. The point with the second lowest stress foreach curve corresponds to outside diameter of 1.25″. The point with thelowest stress for each curve corresponds to outside diameter of 1.315″.As shown in FIG. 44, increasing the strength and/or outside diameter ofthe material and the support member increases the maximum operatingtemperature of the temperature limited heater.

FIGS. 45, 46, 47, and 48 depict examples of embodiments for temperaturelimited heaters able to provide desired heat output and mechanicalstrength for operating temperatures up to about 770° C. for 30,000 hrs.creep-rupture lifetime. The depicted temperature limited heaters havelengths of 1000 ft, copper cores of 0.5″ diameter, and ironferromagnetic conductors with outside diameters of 0.765″. In FIG. 45,the support member in heater portion 548 is 347H stainless steel. Thesupport member in heater portion 550 is Incoloy® alloy 800H. Portion 548has a length of 750 ft. and portion 550 has a length of 250 ft. Theoutside diameter of the support member is 1.315″. In FIG. 46, thesupport member in heater portion 548 is 347H stainless steel. Thesupport member in heater portion 550 is Incoloy® alloy 800H. The supportmember in heater portion 552 is Haynes® HR120® alloy. Portion 548 has alength of 650 ft., portion 550 has a length of 300 ft., and portion 552has a length of 50 ft. The outside diameter of the support member is1.15″. In FIG. 47, the support member in heater portion 548 is 347Hstainless steel. The support member in heater portion 550 is Incoloy®alloy 800H. The support member in heater portion 552 is Haynes® HR120®alloy. Portion 548 has a length of 550 ft., portion 550 has a length of250 ft., and portion 552 has a length of 200 ft. The outside diameter ofthe support member is 1.05″.

In some embodiments, a transition section is used between sections ofthe heater. For example, if one or more portions of the heater havevarying Curie temperatures, a transition section may be used betweenportions to provide strength that compensates for the differences intemperatures in the portions. FIG. 48 depicts another example of anembodiment of a temperature limited heater able to provide desired heatoutput and mechanical strength. The support member in heater portion 548is 347H stainless steel. The support member in heater portion 550 isNF709. The support member in heater portion 552 is 347H. Portion 548 hasa length of 550 ft. and a Curie temperature of 843° C., portion 550 hasa length of 250 ft. and a Curie temperature of 843° C., and portion 552has a length of 180 ft. and a Curie temperature of 770° C. Transitionsection 554 has a length of 20 ft., a Curie temperature of 770° C., andthe support member is NF709.

The materials of the support member along the length of the temperaturelimited heater may be varied to achieve a variety of desired operatingproperties. The choice of the materials of the temperature limitedheater is adjusted depending on a desired use of the temperature limitedheater. TABLE 1 lists examples of materials that may be used for thesupport member. The table provides the hanging stresses (σ) of thesupport members and the maximum operating temperatures of thetemperature limited heaters for several different outside diameters (OD)of the support member. The core diameter and the outside diameter of theiron ferromagnetic conductor in each case are 0.5″ and 0.765″,respectively.

TABLE 1 OD = 1.05″ OD = 1.15″ OD = 1.25″ OD = 1.315″ Material σ (ksi) T(° F.) σ (ksi) T (° F.) σ (ksi) T (° F.) σ (ksi) T (° F.) 347H stainlesssteel 7.55 1310 6.33 1340 5.63 1360 5.31 1370 Incoloy ® alloy 800H 7.551337 6.33 1378 5.63 1400 5.31 1420 Haynes ® HR120 ® 7.57 1450 6.36 14925.65 1520 5.34 1540 alloy HA230 7.91 1475 6.69 1510 5.99 1530 5.67 1540Haynes ® alloy 556 7.65 1458 6.43 1492 5.72 1512 5.41 1520 NF709 7.571440 6.36 1480 5.65 1502 5.34 1512

In certain embodiments, one or more portions of the temperature limitedheater have varying outside diameters and/or materials to providedesired properties for the heater. FIGS. 49 and 50 depict examples ofembodiments for temperature limited heaters that vary the diameterand/or materials of the support member along the length of the heatersto provide desired operating properties and sufficient mechanicalproperties (for example, creep-rupture strength properties) foroperating temperatures up to about 834° C. for 30,000 hrs., heaterlengths of 850 ft, a copper core diameter of 0.5″, and an iron-cobalt(6% by weight cobalt) ferromagnetic conductor outside diameter of 0.75″.In FIG. 49, portion 548 is 347H stainless steel with a length of 300 ftand an outside diameter of 1.15″. Portion 550 is NF709 with a length of400 ft and an outside diameter of 1.15″. Portion 552 is NF709 with alength of 150 ft and an outside diameter of 1.25″. In FIG. 50, portion548 is 347H stainless steel with a length of 300 ft and an outsidediameter of 1.15″. Portion 550 is 347H stainless steel with a length of100 ft and an outside diameter of 1.20″. Portion 552 is NF709 with alength of 350 ft and an outside diameter of 1.20″. Portion 556 is NF709with a length of 100 ft and an outside diameter of 1.25″.

In certain embodiments, one or more portions of the temperature limitedheater have varying dimensions and/or varying materials to providedifferent power outputs along the length of the heater. More or lesspower output may be provided by varying the selected temperature (forexample, the Curie temperature) of the temperature limited heater byusing different ferromagnetic materials along its length and/or byvarying the electrical resistance of the heater by using differentdimensions in the heat generating member along the length of the heater.Different power outputs along the length of the temperature limitedheater may be needed to compensate for different thermal properties inthe formation adjacent to the heater. For example, an oil shaleformation may have different water-filled porosities, dawsonitecompositions, and/or nahcolite compositions at different depths in theformation. Portions of the formation with higher water-filledporosities, higher dawsonite compositions, and/or higher nahcolitecompositions may need more power input than portions with lowerwater-filled porosities, lower dawsonite compositions, and/or lowernahcolite compositions to achieve a similar heating rate. Power outputmay be varied along the length of the heater so that the portions of theformation with different properties (such as water-filled porosities,dawsonite compositions, and/or nahcolite compositions) are heated atapproximately the same heating rate.

In certain embodiments, portions of the temperature limited heater havedifferent selected self-limiting temperatures (for example, Curietemperatures), materials, and/or dimensions to compensate for varyingthermal properties of the formation along the length of the heater. Forexample, Curie temperatures, support member materials, and/or dimensionsof the portions of the heaters depicted in FIGS. 45-50 may be varied toprovide varying power outputs and/or operating temperatures along thelength of the heater.

As one example, in an embodiment of the temperature limited heaterdepicted in FIG. 45, portion 550 may be used to heat portions of theformation that, on average, have higher water-filled porosities,dawsonite compositions, and/or nahcolite compositions than portions ofthe formation heated by portion 548. Portion 550 may provide less poweroutput than portion 548 to compensate for the differing thermalproperties of the different portions of the formation so that the entireformation is heated at an approximately constant heating rate. Portion550 may require less power output because, for example, portion 550 isused to heat portions of the formation with low water-filled porositiesand/or little or no dawsonite. In one embodiment, portion 550 has aCurie temperature of 770° C. (pure iron) and portion 548 has a Curietemperature of 843° C. (iron with added cobalt). Such an embodiment mayprovide more power output from portion 548 so that the temperature lagbetween the two portions is reduced. Adjusting the Curie temperature ofportions of the heater adjusts the selected temperature at which theheater self-limits. In some embodiments, the dimensions of portion 550are adjusted to further reduce the temperature lag so that the formationis heated at an approximately constant heating rate throughout theformation. Dimensions of the heater may be adjusted to adjust theheating rate of one or more portions of the heater. For example, thethickness of an outer conductor in portion 550 may be increased relativeto the ferromagnetic member and/or the core of the heater so that theportion has a higher electrical resistance and the portion provides ahigher power output below the Curie temperature of the portion.

Reducing the temperature lag between different portions of the formationmay reduce the overall time needed to bring the formation to a desiredtemperature. Reducing the time needed to bring the formation to thedesired temperature reduces heating costs and produces desirableproduction fluids more quickly.

Temperature limited heaters with varying Curie temperatures may alsohave varying support member materials to provide mechanical strength forthe heater (for example, to compensate for hanging stress of the heaterand/or provide sufficient creep-rupture strength properties). Forexample, in the embodiment of the temperature limited heater depicted inFIG. 48, portions 548 and 550 have a Curie temperature of 843° C.Portion 548 has a support member made of 347H stainless steel. Portion550 has a support member made of NF709. Portion 552 has a Curietemperature of 770° C. and a support member made of 347H stainlesssteel. Transition section 554 has a Curie temperature of 770° C. and asupport member made of NF709. Transition section 554 may be short inlength compared to portions 548, 550, and 552. Transition section 554may be placed between portions 550 and 552 to compensate for thetemperature and material differences between the portions. For example,transition section 554 may be used to compensate for differences increep properties between portions 550 and 552.

Such a substantially vertical temperature limited heater may have lessexpensive, lower strength materials in portion 552 because of the lowerCurie temperature in this portion of the heater. For example, 347Hstainless steel may be used for the support member because of the lowermaximum operating temperature of portion 552 as compared to portion 550.Portion 550 may require more expensive, higher strength material becauseof the higher operating temperature of portion 550 due to the higherCurie temperature in this portion.

In some embodiments, a relatively thin conductive layer is used toprovide the majority of the electrically resistive heat output of thetemperature limited heater at temperatures up to a temperature at ornear the Curie temperature of the ferromagnetic conductor. Such atemperature limited heater may be used as the heating member in aninsulated conductor heater. The heating member of the insulatedconductor heater may be located inside a sheath with an insulation layerbetween the sheath and the heating member.

FIGS. 51A and 51B depict cross-sectional representations of anembodiment of the insulated conductor heater with the temperaturelimited heater as the heating member. Insulated conductor 558 includescore 508, ferromagnetic conductor 512, inner conductor 490, electricalinsulator 500, and jacket 506. Core 508 is a copper core. Ferromagconductor 512 is, for example, iron or an iron alloy.

Inner conductor 490 is a relatively thin conductive layer ofnon-ferromagnetic material with a higher electrical conductivity thanferromagnetic conductor 512. In certain embodiments, inner conductor 490is copper. Inner conductor 490 may be a copper alloy. Copper alloystypically have a flatter resistance versus temperature profile than purecopper. A flatter resistance versus temperature profile may provide lessvariation in the heat output as a function of temperature up to theCurie temperature. In some embodiments, inner conductor 490 is copperwith 6% by weight nickel (for example, CuNi6 or LOHM™). In someembodiments, inner conductor 490 is CuNi10Fe1Mn alloy. Below the Curietemperature of ferromagnetic conductor 512, the magnetic properties ofthe ferromagnetic conductor confine the majority of the flow ofelectrical current to inner conductor 490. Thus, inner conductor 490provides the majority of the resistive heat output of insulatedconductor 558 below the Curie temperature.

In certain embodiments, inner conductor 490 is dimensioned, along withcore 508 and ferromagnetic conductor 512, so that the inner conductorprovides a desired amount of heat output and a desired turndown ratio.For example, inner conductor 490 may have a cross-sectional area that isaround 2 or 3 times less than the cross-sectional area of core 508.Typically, inner conductor 490 has to have a relatively smallcross-sectional area to provide a desired heat output if the innerconductor is copper or copper alloy. In an embodiment with copper innerconductor 490, core 508 has a diameter of 0.66 cm, ferromagneticconductor 512 has an outside diameter of 0.91 cm, inner conductor 490has an outside diameter of 1.03 cm, electrical insulator 500 has anoutside diameter of 1.53 cm, and jacket 506 has an outside diameter of1.79 cm. In an embodiment with a CuNi6 inner conductor 490, core 508 hasa diameter of 0.66 cm, ferromagnetic conductor 512 has an outsidediameter of 0.91 cm, inner conductor 490 has an outside diameter of 1.12cm, electrical insulator 500 has an outside diameter of 1.63 cm, andjacket 506 has an outside diameter of 1.88 cm. Suc insulated conductorsare typically smaller and cheaper to manufacture than insulatedconductors that do not use the thin inner conductor to provide themajority of heat output below the Curie temperature.

Electrical insulator 500 may be magnesium oxide, aluminum oxide, silicondioxide, beryllium oxide, boron nitride, silicon nitride, orcombinations thereof. In certain embodiments, electrical insulator 500is a compacted powder of magnesium oxide. In some embodiments,electrical insulator 500 includes beads of silicon nitride.

In certain embodiments, a small layer of material is placed betweenelectrical insulator 500 and inner conductor 490 to inhibit copper frommigrating into the electrical insulator at higher temperatures. Forexample, a small layer of nickel (for example, about 0.5 mm of nickel)may be placed between electrical insulator 500 and inner conductor 490.

Jacket 506 is made of a corrosion resistant material such as, but notlimited to, 347 stainless steel, 347H stainless steel, 446 stainlesssteel, or 825 stainless steel. In some embodiments, jacket 506 providessome mechanical strength for insulated conductor 558 at or above theCurie temperature of ferromagnetic conductor 512. In certainembodiments, jacket 506 is not used to conduct electrical current.

In certain embodiments of temperature limited heaters, three temperaturelimited heaters are coupled together in a three-phase wye configuration.Coupling three temperature limited heaters together in the three-phasewye configuration lowers the current in each of the individualtemperature limited heaters because the current is split between thethree individual heaters. Lowering the current in each individualtemperature limited heater allows each heater to have a small diameter.The lower currents allow for higher relative magnetic permeabilities ineach of the individual temperature limited heaters and, thus, higherturndown ratios. In addition, there may be no return current needed foreach of the individual temperature limited heaters. Thus, the turndownratio remains higher for each of the individual temperature limitedheaters than if each temperature limited heater had its own returncurrent path.

In the three-phase wye configuration, individual temperature limitedheaters may be coupled together by shorting the sheaths, jackets, orcanisters of each of the individual temperature limited heaters to theelectrically conductive sections (the conductors providing heat) attheir terminating ends (for example, the ends of the heaters at thebottom of a heater wellbore). In some embodiments, the sheaths, jackets,canisters, and/or electrically conductive sections are coupled to asupport member that supports the temperature limited heaters in thewellbore.

FIG. 52A depicts an embodiment for installing and coupling heaters in awellbore. The embodiment in FIG. 52A depicts insulated conductor heatersbeing installed into the wellbore. Other types of heaters, such asconductor-in-conduit heaters, may also be installed in the wellboreusing the embodiment depicted. Also, in FIG. 52A, two insulatedconductors 558 are shown while a third insulated conductor is not seenfrom the view depicted. Typically, three insulated conductors 558 wouldbe coupled to support member 560, as shown in FIG. 52B. In anembodiment, support member 560 is a thick walled 347H pipe. In someembodiments, thermocouples or other temperature sensors are placedinside support member 560. The three insulated conductors may be coupledin a three-phase wye configuration.

In FIG. 52A, insulated conductors 558 are coiled on coiled tubing rigs562. As insulated conductors 558 are uncoiled from rigs 562, theinsulated conductors are coupled to support member 560. In certainembodiments, insulated conductors 558 are simultaneously uncoiled and/orsimultaneously coupled to support member 560. Insulated conductors 558may be coupled to support member 560 using metal (for example, 304stainless steel or Inconel® alloys) straps 564. In some embodiments,insulated conductors 558 are coupled to support member 560 using othertypes of fasteners such as buckles, wire holders, or snaps. Supportmember 560 along with insulated conductors 558 are installed intoopening 522. In some embodiments, insulated conductors 558 are coupledtogether without the use of a support member. For example, one or morestraps 564 may be used to couple insulated conductors 558 together.

Insulated conductors 558 may be electrically coupled to each other at alower end of the insulated conductors. In a three-phase wyeconfiguration, insulated conductors 558 operate without a current returnpath. In certain embodiments, insulated conductors 558 are electricallycoupled to each other in contactor section 566. In section 566, sheaths,jackets, canisters, and/or electrically conductive sections areelectrically coupled to each other and/or to support member 560 so thatinsulated conductors 558 are electrically coupled in the section.

In certain embodiments, the sheaths of insulated conductors 558 areshorted to the conductors of the insulated conductors. FIG. 52C depictsan embodiment of insulated conductor 558 with the sheath shorted to theconductors. Sheath 506 is electrically coupled to core 508,ferromagnetic conductor 512, and inner conductor 490 using termination568. Termination 568 may be a metal strip or a metal plate at the lowerend of insulated conductor 558. For example, termination 568 may be acopper plate coupled to sheath 506, core 508, ferromagnetic conductor512, and inner conductor 490 so that they are shorted together. In someembodiments, termination 568 is welded or brazed to sheath 506, core508, ferromagnetic conductor 512, and inner conductor 490.

The sheaths of individual insulated conductors 558 may be shortedtogether to electrically couple the conductors of the insulatedconductors. In some embodiments, the sheaths may be shorted togetherbecause the sheaths are in physical contact with each other. Forexample, the sheaths may be in physical contact if the sheaths arestrapped together by straps 564. In some embodiments, the lower ends ofthe sheaths are physically coupled (for example, welded) at the surfaceof opening 522 before insulated conductors 558 are installed into theopening.

In some embodiments, a long temperature limited heater (for example, atemperature limited heater in which the support member provides amajority of the heat output below the Curie temperature of theferromagnetic conductor) is formed from several sections of heater. Thesections of heater may be coupled using a welding process. FIG. 53depicts an embodiment for coupling together sections of a longtemperature limited heater. Ends of ferromagnetic conductors 512 andends of electrical conductors 538 (support members 514) are beveled tofacilitate coupling the sections of the heater. Core 508 has recesses toallow core coupling material 570 to be placed inside the abutted ends ofthe heater. Core coupling material 570 may be a pin or dowel that fitstightly in the recesses of cores 508. Core coupling material 570 may bemade out of the same material as cores 508 or a material suitable forcoupling the cores together. Core coupling material 570 allows theheaters to be coupled together without welding cores 508 together. Cores508 are coupled together as a “pin” or “box” joint.

Beveled ends of ferromagnetic conductors 512 and electrical conductors538 may be coupled together with coupling material 572. In certainembodiments, ends of ferromagnetic conductors 512 and electricalconductors 538 are welded (for example, orbital welded) together.Coupling material 572 may be 625 stainless steel or any other suitablenon-ferromagnetic material for welding together ferromagnetic conductors512 and/or electrical conductors 538. Using beveled ends when couplingtogether sections of the heater may produce a reliable and durablecoupling between the sections of the heater.

During heating with the temperature limited heater, core couplingmaterial 570 may expand more radially than ferromagnetic conductors 512,electrical conductors 538, and/or coupling material 572. The greaterexpansion of core coupling material 570 maintains good electricalcontact with the core coupling material. At the coupling junction of theheater, electricity flows through core coupling material 570 rather thancoupling material 572. This flow of electricity inhibits heat generationat the coupling junction so that the junction remains at lowertemperatures than other portions of the heater during application ofelectrical current to the heater. The corrosion resistance and strengthof the coupling junction is increased by maintaining the junction atlower temperatures.

In certain embodiments, the junction may be enclosed in a shield duringorbital welding to ensure reliability of the weld. If the junction isnot enclosed, disturbance of the inert gas caused by wind, humidity orother conditions may cause oxidation and/or porosity of the weld.Without a shield, a first portion of the weld was formed and allowed tocool. A grinder would be used to remove the oxide layer. The processwould be repeated until the weld was complete. Enclosing the junction inthe shield with an inert gas allows the weld to be formed with nooxidation, thus allowing the weld to be formed in one pass with no needfor grinding. Enclosing the junction increases the safety of forming theweld because the arc of the orbital welder is enclosed in the shieldduring welding. Enclosing the junction in the shield may reduce the timeneeded to form the weld. Without a shield, producing each weld may take30 minutes or more. With the shield, each weld may take 10 minutes orless.

FIG. 54 depicts an embodiment of a shield for orbital welding sectionsof a long temperature limited heater. Orbital welding may also be usedto form canisters for freeze wells from sections of pipe. Shield 574 mayinclude upper plate 576, lower plate 578, inserts 580, wall 582, hingeddoor 584, first clamp member 586, and second clamp member 588. Wall 582may include one or more inert gas inlets. Wall 582, upper plate 576,and/or lower plate 578 may include one or more openings for monitoringequipment or gas purging. Shield 574 is configured to work with anorbital welder, such as AMI Power Supply (Model 227) and AMI OrbitalWeld Head (Model 97-2375) available from Arc Machines, Inc. (Pacoima,Calif., U.S.A.). Inserts 580 may be withdrawn from upper plate 576 andlower plate 578. The orbital weld head may be positioned in shield 574.Shield 574 may be placed around a lower conductor of the conductors thatare to be welded together. When shield is positioned so that the end ofthe lower conductor is at a desired position in the middle of theshield, first clamp member may be fastened to second clamp member tosecure shield 574 to the lower conductor. The upper conductor may bepositioned in shield 574. Inserts 580 may be placed in upper plate 576and lower plate 578.

Hinged door 584 may be closed. The orbital welder may be used to weldthe lower conductor to the upper conductor. Progress of the weldingoperation may be monitored through viewing windows 590. When the weld iscomplete, shield 574 may be supported and first clamp member 586 may beunfastened from second clamp member 588. One or both inserts 580 may beremoved or partially removed from lower plate 578 and upper plate 576 tofacilitate lowering of the conductor. The conductor may be lowered inthe wellbore until the end of the conductor is located at a desiredposition in shield 574. Shield 574 may be secured to the conductor withfirst clamp member 586 and second clamp member 588. Another conductormay be positioned in the shield. Inserts 580 may be positioned in upperand lower plates 576, 578; hinged door is closed 584; and the orbitalwelder is used to weld the conductors together. The process may berepeated until a desired length of conductor is formed.

The shield may be used to weld joints of pipe over an opening in thehydrocarbon containing formation. Hydrocarbon vapors from the formationmay create an explosive atmosphere in the shield even though the inertgas supplied to the shield inhibits the formation of dangerousconcentrations of hydrocarbons in the shield. A control circuit may becoupled to a power supply for the orbital welder to stop power to theorbital welder to shut off the arc forming the weld if the hydrocarbonlevel in the shield rises above a selected concentration. FIG. 55depicts a schematic representation of an embodiment of a shut offcircuit for orbital welding machine 600. An inert gas, such as argon,may enter shield 574 through inlet 602. Gas may exit shield 574 throughpurge 604. Power supply 606 supplies electric orbital welding machine600 through lines 608, 610. Switch 612 may be located in line 608 toorbital welding machine 600. Switch 612 may be electrically coupled tohydrocarbon monitor 614. Hydrocarbon monitor 614 may detect thehydrocarbon concentration in shield 574. If the hydrocarbonconcentration in shield becomes too high, for example, over 25% of alower explosion limit concentration, hydrocarbon monitor 614 may openswitch 612. When switch 612 is open, power to orbital welder 600 isinterrupted and the arc formed by the orbital welder ends.

In some embodiments, the temperature limited heater is used to achievelower temperature heating (for example, for heating fluids in aproduction well, heating a surface pipeline, or reducing the viscosityof fluids in a wellbore or near wellbore region). Varying theferromagnetic materials of the temperature limited heater allows forlower temperature heating. In some embodiments, the ferromagneticconductor is made of material with a lower Curie temperature than thatof 446 stainless steel. For example, the ferromagnetic conductor may bean alloy of iron and nickel. The alloy may have between 30% by weightand 42% by weight nickel with the rest being iron. In one embodiment,the alloy is Invar 36. Invar 36 is 36% by weight nickel in iron and hasa Curie temperature of 277° C. In some embodiments, an alloy is a threecomponent alloy with, for example, chromium, nickel, and iron. Forexample, an alloy may have 6% by weight chromium, 42% by weight nickel,and 52% by weight iron. A 2.5 cm diameter rod of Invar 36 has a turndownratio of approximately 2 to 1 at the Curie temperature. Placing theInvar 36 alloy over a copper core may allow for a smaller rod diameter.A copper core may result in a high turndown ratio. The insulator inlower temperature heater embodiments may be made of a high performancepolymer insulator (such as PFA or PEEK™) when used with alloys with aCurie temperature that is below the melting point or softening point ofthe polymer insulator.

In certain embodiments, a conductor-in-conduit temperature limitedheater is used in lower temperature applications by using lower Curietemperature ferromagnetic materials. For example, a lower Curietemperature ferromagnetic material may be used for heating inside suckerpump rods. Heating sucker pump rods may be useful to lower the viscosityof fluids in the sucker pump or rod and/or to maintain a lower viscosityof fluids in the sucker pump rod. Lowering the viscosity of the oil mayinhibit sticking of a pump used to pump the fluids. Fluids in the suckerpump rod may be heated up to temperatures less than about 250° C. orless than about 300° C. Temperatures need to be maintained below thesevalues to inhibit coking of hydrocarbon fluids in the sucker pumpsystem.

FIG. 56 depicts an embodiment of a temperature limited heater with a lowtemperature ferromagnetic outer conductor. Outer conductor 502 is glasssealing Alloy 42-6. Alloy 42-6 may be obtained from Carpenter Metals(Reading, Pa., U.S.A.) or Anomet Products, Inc. In some embodiments,outer conductor 502 includes other compositions and/or materials to getvarious Curie temperatures (for example, Carpenter TemperatureCompensator “32” (Curie temperature of 199° C.; available from CarpenterMetals) or Invar 36). In an embodiment, conductive layer 510 is coupled(for example, clad, welded, or brazed) to outer conductor 502.Conductive layer 510 is a copper layer. Conductive layer 510 improves aturndown ratio of outer conductor 502. Jacket 506 is a ferromagneticmetal such as carbon steel. Jacket 506 protects outer conductor 502 froma corrosive environment. Inner conductor 490 may have electricalinsulator 500. Electrical insulator 500 may be a mica tape winding withoverlaid fiberglass braid. In an embodiment, inner conductor 490 andelectrical insulator 500 are a 4/0 MGT-1000 furnace cable or 3/0MGT-1000 furnace cable. 4/0 MGT-1000 furnace cable or 3/0 MGT-1000finnace cable is available from Allied Wire and Cable (Phoenixville,Pa., U.S.A.). In some embodiments, a protective braid such as astainless steel braid may be placed over electrical insulator 500.Conductive section 504 electrically couples inner conductor 490 to outerconductor 502 and/or jacket 506. In some embodiments, jacket 506 touchesor electrically contacts conductive layer 510 (for example, if theheater is placed in a horizontal configuration). If jacket 506 is aferromagnetic metal such as carbon steel (with a Curie temperature abovethe Curie temperature of outer conductor 502), current will propagateonly on the inside of the jacket. Thus, the outside of the jacketremains electrically uncharged during operation. In some embodiments,jacket 506 is drawn down (for example, swaged down in a die) ontoconductive layer 510 so that a tight fit is made between the jacket andthe conductive layer. The heater may be spooled as coiled tubing forinsertion into a wellbore. In other embodiments, an annular space ispresent between conductive layer 510 and jacket 506, as depicted in FIG.56.

FIG. 57 depicts an embodiment of a temperature limitedconductor-in-conduit heater. Conduit 518 is a hollow sucker rod made ofa ferromagnetic metal such as Alloy 42-6, Alloy 32, Alloy 52, Invar 36,iron-nickel-chromium alloys, iron-nickel alloys, nickel alloys, ornickel-chromium alloys. Inner conductor 490 has electrical insulator500. Electrical insulator 500 is a mica tape winding with overlaidfiberglass braid. In an embodiment, inner conductor 490 and electricalinsulator 500 are a 4/0 MGT-1000 furnace cable or 3/0 MGT-1000 furnacecable. In some embodiments polymer insulations are used for lowertemperature Curie heaters. In certain embodiments, a protective braid isplaced over electrical insulator 500. Conduit 518 has a wall thicknessthat is greater than the skin depth at the Curie temperature (forexample, 2 to 3 times the skin depth at the Curie temperature). In someembodiments, a more conductive conductor is coupled to conduit 518 toincrease the turndown ratio of the heater.

FIG. 58 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater. Conductor 516 iscoupled (for example, clad, coextruded, press fit, or drawn inside) toferromagnetic conductor 512. A metallurgical bond between conductor 516and ferromagnetic conductor 512 is favorable. Ferromagnetic conductor512 is coupled to the outside of conductor 516 so that currentpropagates through the skin depth of the ferromagnetic conductor at roomtemperature. Conductor 516 provides mechanical support for ferromagneticconductor 512 at elevated temperatures. Ferromagnetic conductor 512 isiron, an iron alloy (for example, iron with 10% to 27% by weightchromium for corrosion resistance), or any other ferromagnetic material.In one embodiment, conductor 516 is 304 stainless steel andferromagnetic conductor 512 is 446 stainless steel. Conductor 516 andferromagnetic conductor 512 are electrically coupled to conduit 518 withsliding connector 528. Conduit 518 may be a non-ferromagnetic materialsuch as austenitic stainless steel.

FIG. 59 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater. Conduit 518 is coupledto ferromagnetic conductor 512 (for example, clad, press fit, or drawninside of the ferromagnetic conductor). Ferromagnetic conductor 512 iscoupled to the inside of conduit 518 to allow current to propagatethrough the skin depth of the ferromagnetic conductor at roomtemperature. Conduit 518 provides mechanical support for ferromagneticconductor 512 at elevated temperatures. Conduit 518 and ferromagneticconductor 512 are electrically coupled to conductor 516 with slidingconnector 528.

FIG. 60 depicts a cross-sectional view of an embodiment of aconductor-in-conduit temperature limited heater. Conductor 516 maysurround core 508. In an embodiment, conductor 516 is 347H stainlesssteel and core 508 is copper. Conductor 516 and core 508 may be formedtogether as a composite conductor. Conduit 518 may include ferromagneticconductor 512. In an embodiment, ferromagnetic conductor 512 is SumitomoHCM12A or 446 stainless steel. Ferromagnetic conductor 512 may have aSchedule XXH thickness so that the conductor is inhibited fromdeforming. In certain embodiments, conduit 518 also includes jacket 506.Jacket 506 may include corrosion resistant material that inhibitselectrons from flowing away from the heater and into a subsurfaceformation at higher temperatures (for example, temperatures near theCurie temperature of ferromagnetic conductor 512). For example, jacket506 may be about a 0.4 cm thick sheath of 410 stainless steel.Inhibiting electrons from flowing to the formation may increase thesafety of using the heater in the subsurface formation.

FIG. 61 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor. Insulated conductor 558 may include core 508, electricalinsulator 500, and jacket 506. Jacket 506 may be made of a corrosionresistant material (for example, stainless steel). Endcap 616 may beplaced at an end of insulated conductor 558 to couple core 508 tosliding connector 528. Endcap 616 may be made of non-corrosive,electrically conducting materials such as nickel or stainless steel.Endcap 616 may be coupled to the end of insulated conductor 558 by anysuitable method (for example, welding, soldering, or braising). Slidingconnector 528 may electrically couple core 508 and endcap 616 toferromagnetic conductor 512. Conduit 518 may provide support forferromagnetic conductor 512 at elevated temperatures.

FIG. 62 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor. Insulated conductor 558 includes core 508, electricalinsulator 500, and jacket 506. Jacket 506 is made of a highlyelectrically conductive material such as copper. Core 508 is made of alower temperature ferromagnetic material such as such as Alloy 42-6,Alloy 32, Invar 36, iron-nickel-chromium alloys, iron-nickel alloys,nickel alloys, or nickel-chromium alloys. In certain embodiments, thematerials of jacket 506 and core 508 are reversed so that the jacket isthe ferromagnetic conductor and the core is the highly conductiveportion of the heater. Ferromagnetic material used in jacket 506 or core508 may have a thickness greater than the skin depth at the Curietemperature (for example, 2 to 3 times the skin depth at the Curietemperature). Endcap 616 is placed at an end of insulated conductor 558to couple core 508 to sliding connector 528. Endcap 616 is made ofcorrosion resistant, electrically conducting materials such as nickel orstainless steel. In certain embodiments, conduit 518 is a hollow suckerrod made from, for example, carbon steel.

In certain embodiments, a temperature limited heater includes a flexiblecable (for example, a furnace cable) as the inner conductor. Forexample, the inner conductor may be a 27% nickel-clad or stainlesssteel-clad stranded copper wire with four layers of mica tape surroundedby a layer of ceramic and/or mineral fiber (for example, alumina fiber,aluminosilicate fiber, borosilicate fiber, or aluminoborosilicatefiber). A stainless steel-clad stranded copper wire furnace cable may beavailable from Anomet Products, Inc. The inner conductor may be ratedfor applications at temperatures of 1000° C. or higher. The innerconductor may be pulled inside a conduit. The conduit may be aferromagnetic conduit (for example, a ¾″ Schedule 80 446 stainless steelpipe). The conduit may be covered with a layer of copper, or otherelectrical conductor, with a thickness of about 0.3 cm or any othersuitable thickness. The assembly may be placed inside a support conduit(for example, a 1¼″ Schedule 80 347H or 347HH stainless steel tubular).The support conduit may provide additional creep-rupture strength andprotection for the copper and the inner conductor. For uses attemperatures greater than about 1000° C., the inner copper conductor maybe plated with a more corrosion resistant alloy (for example, Incoloy®825) to inhibit oxidation. In some embodiments, the top of thetemperature limited heater is sealed to inhibit air from contacting theinner conductor.

The temperature limited heater may be a single-phase heater or athree-phase heater. In a three-phase heater embodiment, the temperaturelimited heater has a delta or a wye configuration. Each of the threeferromagnetic conductors in the three-phase heater may be inside aseparate sheath. A connection between conductors may be made at thebottom of the heater inside a splice section. The three conductors mayremain insulated from the sheath inside the splice section.

FIG. 63 depicts an embodiment of a three-phase temperature limitedheater with ferromagnetic inner conductors. Each leg 618 has innerconductor 490, core 508, and jacket 506. Inner conductors 490 areferritic sta steel or 1% carbon steel. Inner conductors 490 have core508. Core 508 may be copper. Each inner conductor 490 is coupled to itsown jacket 506. Jacket 506 is a sheath made of a corrosion resistantmaterial (such as 304H stainless steel). Electrical insulator 500 isplaced between inner conductor 490 and jacket 506. Inner conductor 490is ferritic stainless steel or carbon steel with an outside diameter of1.14 cm and a thickness of 0.445 cm. Core 508 is a copper core with a0.25 cm diameter. Each leg 618 of the heater is coupled to terminalblock 620. Terminal block 620 is filled with insulation material 622 andhas an outer surface of stainless steel. Insulation material 622 is, insome embodiments, silicon nitride, boron nitride, magnesium oxide orother suitable electrically insulating material. Inner conductors 490 oflegs 618 are coupled (welded) in terminal block 620. Jackets 506 of legs618 are coupled (welded) to an outer surface of terminal block 620.Terminal block 620 may include two halves coupled around the coupledportions of legs 618.

In some embodiments, the three-phase heater includes three legs that arelocated in separate wellbores. The legs may be coupled in a commoncontacting section (for example, a central wellbore, a connectingwellbore, or a solution filled contacting section). FIG. 64 depicts anembodiment of temperature limited heaters coupled in a three-phaseconfiguration. Each leg 624, 626, 628 may be located in separateopenings 522 in hydrocarbon layer 460. Each leg 624, 626, 628 mayinclude heating element 630. Each leg 624, 626, 628 may be coupled tosingle contacting element 632 in one opening 522. Contacting element 632may electrically couple legs 624, 626, 628 together in a three-phaseconfiguration. Contacting element 632 may be located in, for example, acentral opening in the formation. Contacting element 632 may be locatedin a portion of opening 522 below hydrocarbon layer 460 (for example, inthe underburden). In certain embodiments, magnetic tracking of amagnetic element located in a central opening (for example, opening 522of leg 626) is used to guide the formation of the outer openings (forexample, openings 522 of legs 624 and 628) so that the outer openingsintersect the central opening. The central opening may be formed firstusing standard wellbore drilling methods. Contacting element 632 mayinclude funnels, guides, or catchers for allowing each leg to beinserted into the contacting element.

FIG. 65 depicts an embodiment of three heaters coupled in a three-phaseconfiguration. Conductor “legs” 624, 626, 628 are coupled to three-phasetransformer 634. Transformer 634 may be an isolated three-phasetransformer. In certain embodiments, transformer 634 providesthree-phase output in a wye configuration, as shown in FIG. 65. Input totransformer 634 may be made in any input configuration (such as thedelta configuration shown in FIG. 65). Legs 624, 626, 628 each includelead-in conductors 636 in the overburden of the formation coupled toheating elements 630 in hydrocarbon layer 460. Lead-in conductors 636include copper with an insulation layer. For 115 example, lead-inconductors 636 may be a 4-0 copper cables with TEFLON® insulation, acopper rod with polyurethane insulation, or other metal conductors suchas bare copper or aluminum. In certain embodiments, lead-in conductors636 are located in an overburden portion of the formation. Theoverburden portion may include overburden casings 530. Heating elements630 may be temperature limited heater heating elements. In anembodiment, heating elements 630 are 410 stainless steel rods (forexample, 3.1 cm diameter 410 stainless steel rods). In some embodiments,heating elements 630 are composite temperature limited heater heatingelements (for example, 347 stainless steel, 410 stainless steel, coppercomposite heating elements; 347 stainless steel, iron, copper compositeheating elements; or 410 stainless steel and copper composite heatingelements). In certain embodiments, heating elements 630 have a length ofat least about 10 m to about 2000 m, about 20 m to about 400 m, or about30 m to about 300 m.

In certain embodiments, heating elements 630 are exposed to hydrocarbonlayer 460 and fluids from the hydrocarbon layer. Thus, heating elements630 are “bare metal” or “exposed metal” heating elements. Heatingelements 630 may be made from a material that has an acceptablesulfidation rate at high temperatures used for pyrolyzing hydrocarbons.In certain embodiments, heating elements 630 are made from material thathas a sulfidation rate that decreases with increasing temperature overat least a certain temperature range (for example, 500° C. to 650° C.,530° C. to 650° C., or 550° C. to 650° C. ). For example, 410 stainlesssteel may have a sulfidation rate that decreases with increasingtemperature between 530° C. and 650° C. Using such materials reducescorrosion problems due to sulfur-containing gases (such as H₂S) from theformation. In certain embodiments, heating elements 630 are made frommaterial that has a sulfidation rate below a selected value in atemperature range. In some embodiments, heating elements 630 are madefrom material that has a sulfidation rate at most about 25 mils per yearat a temperature between about 800° C. and about 880° C. In someembodiments, the sulfidation rate is at most about 35 mils per year at atemperature between about 800° C. and about 880° C., at most about 45mils per year at a temperature between about 800° C. and about 880° C.,or at most about 55 mils per year at a temperature between about 800° C.and about 880° C. Heating elements 630 may also be substantially inertto galvanic corrosion.

In some embodiments, heating elements 630 have a thin electricallyinsulating layer such as aluminum oxide or thermal spray coated aluminumoxide. In some embodiments, the thin electrically insulating layer is aceramic composition such as an enamel coating. Enamel coatings include,but are not limited to, high temperature porcelain enamels. Hightemperature porcelain enamels may include silicon dioxide, boron oxide,alumina, and alkaline earth oxides (CaO or MgO), and minor amounts ofalkali oxides (Na₂O, K₂O, LiO). The enamel coating may be applied as afinely ground slurry by dipping the heating element into the slurry orspray coating the heating element with the slurry. The coated heatingelement is then heated in a furnace until the glass transitiontemperature is reached so that the slurry spreads over the surface ofthe heating element and makes the porcelain enamel coating. Theporcelain enamel coating contracts when cooled below the glasstransition temperature so that the coating is in compression. Thus, whenthe coating is heated during operation of the heater, the coating isable to expand with the heater without cracking.

The thin electrically insulating layer has low thermal impedanceallowing heat transfer from the heating element to the formation whileinhibiting current leakage between heating elements in adjacent openingsand/or current leakage into the formation. In certain embodiments, thethin electrically insulating layer is stable at temperatures above atleast 350° C., above 500° C., or above 800° C. In certain embodiments,the thin electrically insulating layer has an emissivity of at least0.7, at least 0.8, or at least 0.9. Using the thin electricallyinsulating layer may allow for long heater lengths in the formation withlow current leakage.

Heating elements 630 may be coupled to contacting elements 632 at ornear the underburden of the formation. Contacting elements 632 arecopper or aluminum rods or other highly conductive materials. In certainembodiments, transition sections 638 are located between lead-inconductors 636 and heating elements 630, and/or between heating elements630 and contacting elements 632. Transition sections 638 may be made ofa conductive material that is corrosion resistant such as 347 stainlesssteel over a copper core. In certain embodiments, transition sections638 are made of materials that electrically couple lead-in conductors636 and heating elements 630 while providing little or no heat output.Thus, transition sections 638 help to inhibit overheating of conductorsand insulation used in lead-in conductors 636 by spacing the lead-inconductors from heating elements 630. Transition section 638 may have alength of between about 3 m and about 9 m (for example, about 6 m).

Contacting elements 632 are coupled to contactor 640 in contactingsection 642 to electrically couple legs 624, 626, 628 to each other. Insome embodiments, contact solution 644 (for example, conductive cement)is placed in contacting section 642 to electrically couple contactingelements 632 in the contacting section. In certain embodiments, legs624, 626, 628 are substantially parallel in hydrocarbon layer 460 andleg 624 continues substantially vertically into contacting section 642.The other two legs 626, 628 are directed (for example, by directionallydrilling the wellbores for the legs) to intercept leg 624 in contactingsection 642.

Each leg 624, 626, 628 may be one leg of a three-phase heater embodimentso that the legs are substantially electrically isolated from otherheaters in the formation and are substantially electrically isolatedfrom the formation. Legs 624, 626, 628 may be arranged in a triangularpattern so that the three legs form a triangular shaped three-phaseheater. In an embodiment, legs 624, 626, 628 are arranged in atriangular pattern with 12 m spacing between the legs (each side of thetriangle has a length of 12 m).

In certain embodiments, the thin electrically insulating layer allowsfor relatively long, substantially horizontal heater leg lengths in thehydrocarbon layer with a substantially u-shaped heater. FIG. 66 depictsa side-view representation of an embodiment of a substantially u-shapedthree-phase heater. First ends of legs 624, 626, 628 are coupled totransformer 634 at first location 646. In an embodiment, transformer 634is a three-phase AC transformer. Ends of legs 624, 626, 628 areelectrically coupled together with connector 648 at second location 650.Connector 648 electrically couples the ends of legs 624, 626, 628 sothat the legs can be operated in a three-phase configuration. In certainembodiments, legs 624, 626, 628 are coupled to operate in a three-phasewye configuration. In certain embodiments, legs 624, 626, 628 aresubstantially parallel in hydrocarbon layer 460. In certain embodiments,legs 624, 626, 628 are arranged in a triangular pattern in hydrocarbonlayer 460. In certain embodiments, heating elements 630 include a thinelectrically insulating material (such as a porcelain enamel coating) toinhibit current leakage from the heating elements. In certainembodiments, legs 624, 626, 628 are electrically coupled so that thelegs are substantially electrically isolated from other heaters in theformation and are substantially electrically isolated from theformation.

In certain embodiments, overburden casings (for example, overburdencasings 530, depicted in FIGS. 65 and 66) in overburden 458 includematerials that inhibit ferromagnetic effects in the casings. Inhibitingferromagnetic effects in casings 530 reduces heat losses to theoverburden. In some embodiments, casings 530 may include non-metallicmaterials such as fiberglass, polyvinylchloride (PVC), chlorinatedpolyvinylchloride (CPVC), or high-density polyethylene (HDPE). HDPEswith working temperatures in a range for use in overburden 458 includeHDPEs available from Dow Chemical Co., Inc. (Midland, Mich., U.S.A.). Anon-metallic casing may also eliminate the need for an insulatedoverburden conductor. In some embodiments, casings 530 include carbonsteel coupled on the inside diameter of a non-ferromagnetic metal (forexample, carbon steel clad with copper or aluminum) to inhibitferromagnetic effects or inductive effects in the carbon steel. Othernon-ferromagnetic metals include, but are not limited to, manganesesteels with at least 10% by weight manganese, iron aluminum alloys withat least 18% by weight aluminum, and austentitic stainless steels suchas 304 stainless steel or 316 stainless steel.

In certain embodiments, one or more non-ferromagnetic materials used incasings 530 are used in a wellhead coupled to the casings and legs 624,626, 628. Using non-ferromagnetic materials in the wellhead inhibitsundesirable heating of components in the wellhead. In some embodiments,a purge gas (for example, carbon dioxide, nitrogen or argon) isintroduced into the wellhead and/or inside of casings 530 to inhibitreflux of heated gases into the wellhead and/or the casings.

In certain embodiments, one or more of legs 624, 626, 628 are installedin the formation using coiled tubing. In certain embodiments, coiledtubing is installed in the formation, the leg is installed inside thecoiled tubing, and the coiled tubing is pulled out of the formation toleave the leg installed in the formation. The leg may be placedconcentrically inside the coiled tubing. In some embodiments, coiledtubing with the leg inside the coiled tubing is installed in theformation and the coiled tubing is removed from the formation to leavethe leg installed in the formation. The coiled tubing may extend only toa junction of the hydrocarbon layer and the contacting section or to apoint at which the leg begins to bend in the contacting section.

FIG. 67 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in the formation. Each triad652 includes legs A, B, C (which may correspond to legs 624, 626, 628depicted in FIGS. 65 and 66) that are electrically coupled by linkage654. Each triad 652 is coupled to its own electrically isolatedthree-phase transformer so that the triads are substantiallyelectrically isolated from each other. Electrically isolating the triadsinhibits net current flow between triads.

The phases of each triad 652 may be arranged so that legs A, B, Ccorrespond between triads as shown in FIG. 67. In FIG. 67, legs A, B, Care arranged such that a phase leg (for example, leg A) in a given triadis about two triad heights from a same phase leg (leg A) in an adjacenttriad. The triad height is the distance from a vertex of the triad to amidpoint of the line intersecting the other two vertices of the triad.In certain embodiments, the phases of triads 652 are arranged to inhibitnet current flow between individual triads. There may be some leakage ofcurrent within an individual triad but little net current flows betweentwo triads due to the substantial electrical isolation of the triadsand, in certain embodiments, the arrangement of the triad phases.

In the early stages of heating, an exposed heating element (for example,heating element 630 depicted in FIGS. 65 and 66) may leak some currentto water or other fluids that are electrically conductive in theformation so that the formation itself is heated. After water or otherelectrically conductive fluids are removed from the wellbore (forexample, vaporized or produced), the heating elements becomeelectrically isolated from the formation. Later, when water is removedfrom the formation, the formation becomes even more electricallyresistant and heating of the formation occurs even more predominantlyvia thermally conductive and/or radiative heating. Typically, theformation (the hydrocarbon layer) has an initial electrical resistancethat averages at least 10 ohm·m. In some embodiments, the formation hasan initial electrical resistance of at least 100 ohm·m or of at least300 ohm·m.

Using the temperature limited heaters as the heating elements limits theeffect of water saturation on heater efficiency. With water in theformation and in heater wellbores, there is a tendency for electricalcurrent to flow between heater elements at the top of the hydrocarbonlayer where the voltage is highest and cause uneven heating in thehydrocarbon layer. This effect is inhibited with temperature limitedheaters because the temperature limited heaters reduce localizedoverheating in the heating elements and in the hydrocarbon layer.

In certain embodiments, production wells are placed at a location atwhich there is relatively little or zero voltage potential. Thislocation minimizes stray potentials at the production well. Placingproduction wells at such locations improves the safety of the system andreduces or inhibits undesired heating of the production wells caused byelectrical current flow in the production wells. FIG. 68 depicts a topview representation of the embodiment depicted in FIG. 67 withproduction wells 206. In certain embodiments, production wells 206 arelocated at or near center of triad 652. In certain embodiments,production wells 206 are placed at a location between triads at whichthere is relatively little or zero voltage potential (at a location atwhich voltage potentials from vertices of three triads average out torelatively little or zero voltage potential). For example, productionwell 206 may be at a location equidistant from legs A of one triad, legB of a second triad, and leg C of a third triad, as shown in FIG. 68.

FIG. 69 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a hexagonal pattern in theformation. FIG. 70 depicts a top view representation of an embodiment ofa hexagon from FIG. 69. Hexagon 656 includes two triads of heaters. Thefirst triad includes legs A1, B1, C1 electrically coupled together bylinkages 654 in a three-phase configuration. The second triad includeslegs A2, B2, C2 electrically coupled together by linkages 654 in athree-phase configuration. The triads are arranged so that correspondinglegs of the triads (for example, A1 and A2, B1 and B2, C1 and C2) are atopposite vertices of hexagon 656. The triads are electrically coupledand arranged so that there is relatively little or zero voltagepotential at or near the center of hexagon 656.

Production well 206 may be placed at or near the center of hexagon 656.Placing production well 206 at or near the center of hexagon 656 placesthe production well at a location that reduces or inhibits undesiredheating due to electromagnetic effects caused by electrical current flowin the legs of the triads and increases the safety of the system. Havingtwo triads in hexagon 656 provides for redundant heating aroundproduction well 206. Thus, if one triad fails or has to be turned off,production well 206 still remains at a center of one triad.

As shown in FIG. 69, hexagons 656 may be arranged in a pattern in theformation such that adjacent hexagons are offset. Using electricallyisolated transformers on adjacent hexagons may inhibit electricalpotentials in the formation so that little or no net current leaksbetween hexagons.

Triads of heaters and/or heater legs may be arranged in any shape ordesired pattern. For example, as described above, triads may includethree heaters and/or heater legs arranged in an equilateral triangularpattern. In some embodiments, triads include three heaters and/or heaterlegs arranged in other triangular shapes (for example, an isoscelestriangle or a right angle triangle). In some embodiments, heater legs inthe triad cross each other (for example, criss-cross) in the formation.In certain embodiments, triads includes three heaters and/or heater legsarranged sequentially along a straight line.

FIG. 71 depicts an embodiment with triads coupled to a horizontalconnector well. Triad 652A includes legs 624A, 626A, 628A. Triad 652Bincludes legs 624B, 626B, 628B. Legs 624A, 626A, 628A and 624B, 626B,628B may be arranged along a straight line on the surface of theformation. In some embodiments, legs 624A, 626A, 628A are arranged alonga straight line and offset from legs 624B, 626B, 628B, which may bearranged along a straight line. Legs 624A, 626A, 628A and legs 624B,626B, 628B include heating elements 630 located in hydrocarbon layer460. Lead-in conductors 636 couple heating elements 630 to the surfaceof the formation. Heating elements 630 are coupled to contactingelements 632 at or near the underburden of the formation. In certainembodiments, transition sections (for example, transition sections 638depicted in FIG. 65) are located between lead-in conductors 636 andheating elements 630, and/or between heating elements 630 and contactingelements 632.

Contacting elements 632 are coupled to contactor 640 in contactingsection 642 to electrically couple legs 624A, 626A, 628A to each otherto form triad 652A and electrically couple legs 624B, 626B, 628B to eachother to form triad 652B. In certain embodiments, contactor 640 is aground conductor so that triad 652A and/or triad 652B may be coupled inthree-phase wye configurations. In certain embodiments, triad 652A andtriad 652B are electrically isolated from each other. In someembodiments, triad 652A and triad 652B are electrically coupled to eachother (for example, electrically coupled in series or parallel).

In certain embodiments, contactor 640 is a substantially horizontalcontactor located in contacting section 642. Contactor 640 may be acasing or a solid rod placed in a wellbore drilled substantiallyhorizontally in contacting section 642. Legs 624A, 626A, 628A and legs624B, 626B, 628B may be electrically coupled to contactor 640 by anymethod described herein or any method known in the art. For example,containers with thermite powder are coupled to contactor 640 (forexample, by welding or brazing the containers to the contactor); legs624A, 626A, 628A and legs 624B, 626B, 628B are placed inside thecontainers; and the thermite powder is activated to electrically couplethe legs to the contactor. The containers may be coupled to contactor640 by, for example, placing the containers in holes or recesses incontactor 640 or coupled to the outside of the contactor and thenbrazing or welding the containers to the contactor.

As shown in FIG. 65, contacting elements 632 of legs 624, 626, 628 maybe coupled using contactor 640 and/or contact solution 644. In certainembodiments, contacting elements 632 of legs 624, 626, 628 arephysically coupled, for example, through soldering, welding, or othertechniques. FIGS. 72 and 73 depict embodiments for coupling contactingelements 632 of legs 624, 626, 628. Legs 626, 628 may enter the wellboreof leg 624 from any direction desired. In one embodiment, legs 626, 628enter the wellbore of leg 624 from approximately the same side of thewellbore, as shown in FIG. 72. In an alternative embodiment, legs 626,628 enter the wellbore of leg 624 from approximately opposite sides ofthe wellbore, as shown in FIG. 73.

Container 658 is coupled to contacting element 632 of leg 624. Container658 may be soldered, welded, or otherwise electrically coupled tocontacting element 632. Container 658 is a metal can or other containerwith at least one opening for receiving one or more contacting elements632. In an embodiment, container 658 is a can that has an opening forreceiving contacting elements 632 from legs 626, 628, as shown in FIG.72. In certain embodiments, wellbores for legs 626, 628 are drilledparallel to the wellbore for leg 624 through the hydrocarbon layer thatis to be heated and directionally drilled below the hydrocarbon layer tointercept wellbore for leg 624 at an angle between about 10° and about20° from vertical. Wellbores may be directionally drilled using knowntechniques such as techniques used by Vector Magnetics, Inc.

In some embodiments, contacting elements 632 contact the bottom ofcontainer 658. Contacting elements 632 may contact the bottom ofcontainer 658 and/or each other to promote electrical connection betweenthe contacting elements and/or the container. In certain embodiments,end portions of contacting elements 632 are annealed to a “dead soft”condition to facilitate entry into container 658. In some embodiments,rubber or other softening material is attached to end portions ofcontacting elements 632 to facilitate entry into container 658. In someembodiments, contacting elements 632 include reticulated sections, suchas knuckle-joints or limited rotation knuckle-joints, to facilitateentry into container 658.

In certain embodiments, an electrical coupling material is placed incontainer 658. The electrical coupling material may line the walls ofcontainer 658 or fill up a portion of the container. In certainembodiments, the electrical coupling material lines an upper portion,such as the funnel-shaped portion shown in FIG. 74, of container 658.The electrical coupling material includes one or more materials thatwhen activated (for example, heated, ignited, exploded, combined, mixed,and/or reacted) form a material that electrically couples one or moreelements to each other. In an embodiment, the coupling materialelectrically couples contacting elements 632 in container 658. In someembodiments, the coupling material metallically bonds to contactingelements 632 so that the contacting elements are metallically bonded toeach other. In some embodiments, container 658 is initially filled witha high viscosity water-based polymer fluid to inhibit drill cuttings orother materials from entering the container prior to using the couplingmaterial to couple the contacting elements. The polymer fluid may be,but is not limited to, a cross-linked XC polymer (available from BaroidIndustrial Drilling Products (Houston, Tex., U.S.A.)), a frac gel, or across-linked polyacrylamide gel.

In certain embodiments, the electrical coupling material is alow-temperature solder that melts at relatively low temperature and whencooled forms an electrical connection to exposed metal surfaces. Incertain embodiments, the electrical coupling material is a solder thatmelts at a temperature below the boiling point of water at the depth ofcontainer 658. In one embodiment, the electrical coupling material is a58% by weight bismuth and 42% by weight tin eutectic alloy. Otherexamples of such solders include, but are not limited to, a 54% byweight bismuth, 16% by weight tin, 30% by weight indium alloy, and a 48%by weight tin, 52% by weight indium alloy. Such low-temperature solderswill displace water upon melting so that the water moves to the top ofcontainer 658. Water at the top of container 658 may inhibit heattransfer into the container and thermally insulate the low-temperaturesolder so that the solder remains at cooler temperatures and does notmelt during heating of the formation using the heating elements.

Container 658 may be heated to activate the electrical coupling materialto facilitate the connection of contacting elements 632. In certainembodiments, container 658 is heated to melt the electrical couplingmaterial in the container. The electrical coupling material flows whenmelted and surrounds contacting elements 632 in container 658. Any waterwithin container 658 will float to the surface of the metal when themetal is melted. The electrical coupling material is allowed to cool andelectrically connects contacting elements 632 to each other. In certainembodiments, contacting elements 632 of legs 626, 628, the inside wallsof container 658, and/or the bottom of the container are initiallypre-tinned with electrical coupling material.

End portions of contacting elements 632 of legs 624, 626, 628 may haveshapes and/or features that enhance the electrical connection betweenthe contacting elements and the coupling material. The shapes and/orfeatures of contacting elements 632 may also enhance the physicalstrength of the connection between the contacting elements and thecoupling material (for example, the shape and/or features of thecontacting element may anchor the contacting element in the couplingmaterial). Shapes and/or features for end portions of contactingelements 632 include, but are not limited to, grooves, notches, holes,threads, serrated edges, openings, and hollow end portions. In certainembodiments, the shapes and/or features of the end portions ofcontacting elements 632 are initially pre-tinned with electricalcoupling material.

FIG. 74 depicts an embodiment of container 658 with an initiator formelting the coupling material. The initiator is an electrical resistanceheating element or any other element for providing heat that activatesor melts the coupling material in container 658. In certain embodiments,heating element 660 is a heating element located in the walls ofcontainer 658. In some embodiments, heating element 660 is located onthe outside of container 658. Heating element 660 may be, for example, anichrome wire, a mineral-insulated conductor, a polymer-insulatedconductor, a cable, or a tape that is inside the walls of container 658or on the outside of the container. In some embodiments, heating element660 wraps around the inside walls of the container or around the outsideof the container. Lead-in wire 662 may be coupled to a power source atthe surface of the formation. Lead-out wire 664 may be coupled to thepower source at the surface of the formation. Lead-in wire 662 and/orlead-out wire 664 may be coupled along the length of leg 624 formechanical support. Lead-in wire 662 and/or lead-out wire 664 may beremoved from the wellbore after melting the coupling material. Lead-inwire 662 and/or lead-out wire 664 may be reused in other wellbores.

In some embodiments, container 658 has a funnel-shape, as shown in FIG.74, that facilitates the entry of contacting elements 632 into thecontainer. In certain embodiments, container 658 is made of or includescopper for good electrical and thermal conductivity. A copper container658 makes good electrical contact with contacting elements (such ascontacting elements 632 shown in FIGS. 72 and 73) if the contactingelements touch the walls and/or bottom of the container.

FIG. 75 depicts an embodiment of container 658 with bulbs on contactingelements 632. Protrusions 666 may be coupled to a lower portion ofcontacting elements 632. Protrusions 668 may be coupled to the innerwall of container 658. Protrusions 666, 668 may be made of copper oranother suitable electrically conductive material. Lower portion ofcontacting element 632 of leg 628 may have a bulbous shape, as shown inFIG. 75. In certain embodiments, contacting element 632 of leg 628 isinserted into container 658. Contacting element 632 of leg 626 isinserted after insert contacting element 632 of leg 628. Both legs maythen be pulled upwards simultaneously. Protrusions 666 may lockcontacting elements 632 into place against protrusions 668 in container658. A friction fit is created between contacting elements 632 andprotrusions 666, 668.

Lower portions of contacting elements 632 inside container 658 mayinclude 410 stainless steel or any other heat generating electricalconductor. Portions of contacting elements 632 above the heat generatingportions of the contacting elements include copper or another highlyelectrically conductive material. Centralizers 524 may be located on theportions of contacting elements 632 above the heat generating portionsof the contacting elements. Centralizers 524 inhibit physical andelectrical contact of portions of contacting elements 632 above the heatgenerating portions of the contacting elements against walls ofcontainer 658.

When contacting elements 632 are locked into place inside container 658by protrusions 666, 668, at least some electrical current may be passbetween the contacting elements through the protrusions. As electricalcurrent is passed through the heat generating portions of contactingelements 632, heat is generated in container 658. The generated heat maymelt coupling material 670 located inside container 658. Water incontainer 658 may boil. The boiling water may convect heat to upperportions of container 658 and aid in melting of coupling material 670.Walls of container 658 may be thermally insulated to reduce heat lossesout of the container and allow the inside of the container to heat upfaster. Coupling material 670 flows down into the lower portion ofcontainer 658 as the coupling material melts. Coupling material 670fills the lower portion of container 658 until the heat generatingportions of contacting elements 632 are below the fill line of thecoupling material. Coupling material 670 then electrically couples theportions of contacting elements 632 above the heat generating portionsof the contacting elements. The resistance of contacting elements 632decreases at this point and heat is no longer generated in thecontacting elements and the coupling materials is allowed to cool.

In certain embodiments, container 658 includes insulation layer 672inside the housing of the container. Insulation layer 672 may includethermally insulating materials to inhibit heat losses from the canister.For example, insulation layer 672 may include magnesium oxide, siliconnitride, or other thermally insulating materials that withstandoperating temperatures in container 658. In certain embodiments,container 658 includes liner 674 on an inside surface of the container.Liner 674 may increase electrical conductivity inside container 658.Liner 674 may include electrically conductive materials such as copperor aluminum.

FIG. 76 depicts an alternative embodiment for container 658. Couplingmaterial in container 658 includes powder 676. Powder 676 is a chemicalmixture that produces a molten metal product from a reaction of thechemical mixture. In an embodiment, powder 676 is thermite powder.Powder 676 lines the walls of container 658 and/or is placed in thecontainer. Igniter 678 is placed in powder 676. Igniter 678 may be, forexample, a magnesium ribbon that when activated ignites the reaction ofpowder 676. When powder 676 reacts, a molten metal produced by thereaction flows and surrounds contacting elements 632 placed in container658. When the molten metal cools, the cooled metal electrically connectscontacting elements 632. In some embodiments, powder 676 is used incombination with another coupling material, such as a low-temperaturesolder, to couple contacting elements 632. The heat of reaction ofpowder 676 may be used to melt the low temperature-solder.

In certain embodiments, an explosive element is placed in container 658,depicted in FIG. 72 or FIG. 76. The explosive element may be, forexample, a shaped charge explosive or other controlled explosiveelement. The explosive element may be exploded to crimp contactingelements 632 and/or container 658 together so that the contactingelements and the container are electrically connected. In someembodiments, an explosive element is used in combination with anelectrical coupling material such as low-temperature solder or thermitepowder to electrically connect contacting elements 632.

FIG. 77 depicts an alternative embodiment for coupling contactingelements 632 of legs 624, 626, 628. Container 658A is coupled tocontacting element 632 of leg 626. Container 658B is coupled tocontacting element 632 of leg 628. Container 658B is sized and shaped tobe placed inside container 658A. Container 658C is coupled to contactingelement 632 of leg 624. Container 658C is sized and shaped to be placedinside container 658B. In some embodiments, contacting element 632 ofleg 624 is placed in container 658B without a container attached to thecontacting element. One or more of containers 658A, 658B, 658C may befilled with a coupling material that is activated to facilitate anelectrical connection between contacting elements 632 as describedabove.

FIG. 78 depicts a cross-sectional representation of an embodiment forcoupling contacting elements using temperature limited heating elements.Contacting elements 632 of legs 624, 626, 628 may have insulation 680 onportions of the contacting elements above container 658. Container 658may be shaped and/or have guides at the top to guide the insertion ofcontacting elements 632 into the container. Coupling material 670 may belocated inside container 658 at or near a top of the container. Couplingmaterial 670 may be, for example, a solder material. In someembodiments, inside walls of container 658 are pre-coated with couplingmaterial or another electrically conductive material such as copper oraluminum. Centralizers 524 may be coupled to contacting elements 632 tomaintain a spacing of the contacting elements in container 658.Container 658 may be tapered at the bottom to push lower portions ofcontacting elements 632 together for at least some electrical contactbetween the lower portions of the contacting elements.

Heating elements 682 may be coupled to portions of contacting elements632 inside container 658. Heating elements 682 may include ferromagneticmaterials such as iron or stainless steel. In an embodiment, heatingelements 682 are iron cylinders clad onto contacting elements 632.Heating elements 682 may be designed with dimensions and materials thatwill produce a desired amount of heat in container 658. In certainembodiments, walls of container 658 are thermally insulated withinsulation layer 672, as shown in FIG. 78 to inhibit heat loss from thecontainer. Heating elements 682 may be spaced so that contactingelements 632 have one or more portions of exposed material insidecontainer 658. The exposed portions include exposed copper or anothersuitable highly electrically conductive material. The exposed portionsallow for better electrical contact between contacting elements 632 andcoupling material 670 after the coupling material has been melted, fillscontainer 658, and is allowed to cool.

In certain embodiments, heating elements 682 operate as temperaturelimited heaters when a time-varying current is applied to the heatingelements. For example, a 400 Hz, AC current may be applied to heatingelements 682. Application of the time-varying current to contactingelements 632 causes heating elements 682 to generate heat and meltcoupling material 670. Heating elements 682 may operate as temperaturelimited heating elements with a self-limiting temperature selected sothat coupling material 670 is not overheated. As coupling material 670fills container 658, the coupling material makes electrical contactbetween portions of exposed material on contacting elements 632 andelectrical current begins to flow through the exposed material portionsrather than heating elements 682. Thus, the electrical resistancebetween the contacting elements decreases. As this occurs, temperaturesinside container 658 begin to decrease and coupling material 670 isallowed to cool to create an electrical contacting section betweencontacting elements 632. In certain embodiments, electrical power tocontacting elements 632 and heating elements 682 is turned off when theelectrical resistance in the system falls below a selected resistance.The selected resistance may indicate that the coupling material hassufficiently electrically connected the contacting elements. In someembodiments, electrical power is supplied to contacting elements 632 andheating elements 682 for a selected amount of time that is determined toprovide enough heat to melt the mass of coupling material 670 providedin container 658.

FIG. 79 depicts a cross-sectional representation of an alternativeembodiment for coupling contacting elements using temperature limitedheating elements. Contacting element 632 of leg 624 may be coupled tocontainer 658 by welding, brazing, or another suitable method. Lowerportion of contacting element 632 of leg 628 may have a bulbous shape.Contacting element 632 of leg 628 is inserted into container 658.Contacting element 632 of leg 626 is inserted after insertion ofcontacting element 632 of leg 628. Both legs may then be pulled upwardssimultaneously. Protrusions 668 may lock contacting elements 632 intoplace and a friction fit may be created between the contacting elements632. Centralizers 524 may inhibit electrical contact between upperportions of contacting elements 632.

Time-varying electrical current may be applied to contacting elements632 so that heating elements 682 generate heat. The generated heat maymelt coupling material 670 located in container 658, as described forthe embodiment depicted in FIG. 78. After cooling of coupling material670, contacting elements 632 of legs 626, 628, shown in FIG. 79, areelectrically coupled in container 658 with the coupling material. Insome embodiments, lower portions of contacting elements 632 haveprotrusions or openings that anchor the contacting elements in cooledcoupling material. Exposed portions of the contacting elements provide alow electrical resistance path between the contacting elements and thecoupling material.

FIG. 80 depicts a cross-sectional representation of another embodimentfor coupling contacting elements using temperature limited heatingelements. Contacting element 632 of leg 624 may be coupled to container658 by welding, brazing, or another suitable method. Lower portion ofcontacting element 632 of leg 628 may have a bulbous shape. Contactingelement 632 of leg 628 is inserted into container 658. Contactingelement 632 of leg 626 is inserted after insertion of contacting element632 of leg 628. Both legs may then be pulled upwards simultaneously.Protrusions 668 may lock contacting elements 632 into place and afriction fit may be created between the contacting elements 632.Centralizers 524 may inhibit electrical contact between upper portionsof contacting elements 632.

End portions 632B of contacting elements 632 may be made of aferromagnetic material such as 410 stainless steel. Portions 632A mayinclude non-ferromagnetic electrically conductive material such ascopper or aluminum. Time-varying electrical current may be applied tocontacting elements 632 so that end portions 632B generate heat due tothe resistance of the end portions. The generated heat may melt couplingmaterial 670 located in container 658, as described for the embodimentdepicted in FIG. 78. After cooling of coupling material 670, contactingelements 632 of legs 626, 628, shown in FIG. 79, are electricallycoupled in container 658 with the coupling material. Portions 632A maybe below the fill line of coupling material 670 so that these portionsof the contacting elements provide a low electrical resistance pathbetween the contacting elements and the coupling material.

FIG. 81 depicts a side view representation of an alternative embodimentfor coupling contacting elements of three legs of a heater. FIG. 82depicts a top view representation of the alternative embodiment forcoupling contacting elements of three legs of a heater depicted in FIG.81. Container 658 may include inner container 684 and outer container686. Inner container 684 may be made of copper or another malleable,electrically conductive metal such as aluminum. Outer container 686 maybe made of a rigid material such as stainless steel. Outer container 686protects inner container 684 and its contents from environmentalconditions outside of container 658.

Inner container 684 may be substantially solid with two openings 688 and690. Inner container 684 is coupled to contacting element 632 of leg624. For example, inner container 684 may be welded or brazed tocontacting element 632 of leg 624. Openings 688, 690 are shaped to allowcontacting elements 632 of legs 626, 628 to enter the openings as shownin FIG. 81. Funnels or other guiding mechanisms may be coupled to theentrances to openings 688, 690 to guide contacting elements 632 of legs626, 628 into the openings. Contacting elements 632 of legs 624, 626,628 may be made of the same material as inner container 684.

Explosive elements 700 may be coupled to the outer wall of innercontainer 684. In certain embodiments, explosive elements 700 areelongated explosive strips that extend along the outer wall of innercontainer 684. Explosive elements 700 may be arranged along the outerwall of inner container 684 so that the explosive elements are alignedat or near the centers of contacting elements 632, as shown in FIG. 82.Explosive elements 700 are arranged in this configuration so that energyfrom the explosion of the explosive elements causes contacting elements632 to be pushed towards the center of inner container 684.

Explosive elements 700 may be coupled to battery 702 and timer 704.Battery 702 may provide power to explosive elements 700 to initiate theexplosion. Timer 704 may be used to control the time for ignitingexplosive elements 700. Battery 702 and timer 704 may be coupled totriggers 706. Triggers 706 may be located in openings 688, 690.Contacting elements 632 may set off triggers 706 as the contactingelements are placed into openings 688, 690. When both triggers 706 inopenings 688, 690 are triggered, timer 704 may initiate a countdownbefore igniting explosive elements 700. Thus, explosive elements 700 arecontrolled to explode only after contacting elements 632 are placedsufficiently into openings 688, 690 so that electrical contact may bemade between the contacting elements and inner container 684 after theexplosions. Explosion of explosive elements 700 crimps contactingelements 632 and inner container 684 together to make electrical contactbetween the contacting elements and the inner container. In certainembodiments, explosive elements 700 fire from the bottom towards the topof inner container 684. Explosive elements 700 may be designed with alength and explosive power (band width) that gives an optimum electricalcontact between contacting elements 632 and inner container 684.

In some embodiments, triggers 706, battery 702, and timer 704 may beused to ignite a powder (for example, copper thermite powder) inside acontainer (for example, container 658 or inner container 684). Battery702 may charge a magnesium ribbon or other ignition device in the powderto initiate reaction of the powder to produce a molten metal product.The molten metal product may flow and then cool to electrically contactthe contacting elements.

In certain embodiments, electrical connection is made between contactingelements 632 through mechanical means. FIG. 83 depicts an embodiment ofcontacting element 632 with a brush contactor. Brush contactor 708 iscoupled to a lower portion of contacting element 632. Brush contactor708 may be made of a malleable, electrically conductive material such ascopper or aluminum. Brush contactor 708 may be a webbing of materialthat is compressible and/or flexible. Centralizer 524 may be located ator near the bottom of contacting element 632.

FIG. 84 depicts an embodiment for coupling contacting elements 632 withbrush contactors 708. Brush contactors 708 are coupled to eachcontacting element 632 of legs 624, 626, 628. Brush contactors 708compress against each other and interlace to electrically couplecontacting elements 632 of legs 624, 626, 628. Centralizers 524 maintainspacing between contacting elements 632 of legs 624, 626, 628 so thatinterference and/or clearance issues between the contacting elements areinhibited.

In certain embodiments, contacting elements 632 (depicted in FIGS.72-84) are coupled in a zone of the formation that is cooler than thelayer of the formation to be heated (for example, in the underburden ofthe formation). Contacting elements 632 are coupled in a cooler zone toinhibit melting of the coupling material and/or degradation of theelectrical connection between the elements during heating of thehydrocarbon layer above the cooler zone. In certain embodiments,contacting elements 632 are coupled in a zone that is at least about 3m, at least about 6 m, or at least about 9 m below the layer of theformation to be heated. In some embodiments, the zone has a standingwater level that is above a depth of containers 658.

In certain embodiments, two legs in separate wellbores intercept in asingle contacting section. FIG. 85 depicts an embodiment of twotemperature limited heaters coupled in a single contacting section. Legs624 and 626 include one or more heating elements 630. Heating elements630 may include one or more electrical conductors. In certainembodiments, legs 624 and 626 are electrically coupled in a single-phaseconfiguration with one leg positively biased versus the other leg sothat current flows downhole through one leg and returns through theother leg.

Heating elements 630 in legs 624 and 626 may be temperature limitedheaters. In certain embodiments, heating elements 630 are solid rodheaters. For example, heating elements 630 may be rods made of a singleferromagnetic conductor element or composite conductors that includeferromagnetic material. During initial heating when water is present inthe formation being heated, heating elements 630 may leak current intohydrocarbon layer 460. The current leaked into hydrocarbon layer 460 mayresistively heat the hydrocarbon layer.

In some embodiments (for example, in oil shale formations), heatingelements 630 do not need support members. Heating elements 630 may bepartially or slightly bent, curved, made into an S-shape, or made into ahelical shape to allow for expansion and/or contraction of the heatingelements. In certain embodiments, solid rod heating elements 630 areplaced in small diameter wellbores (for example, about 3¾″ (about 9.5cm) diameter wellbores). Small diameter wellbores may be less expensiveto drill or form than larger diameter wellbores, and there will be lesscuttings to dispose of.

In certain embodiments, portions of legs 624 and 626 in overburden 458have insulation (for example, polymer insulation) to inhibit heating theoverburden. Heating elements 630 may be substantially vertical andsubstantially parallel to each other in hydrocarbon layer 460. At ornear the bottom of hydrocarbon layer 460, leg 624 may be directionallydrilled towards leg 626 to intercept leg 626 in contacting section 642.Drilling two wellbores to intercept each other may be easier and lessexpensive than drilling three or more wellbores to intercept each other.The depth of contacting section 642 depends on the length of bend in leg624 needed to intercept leg 626. For example, for a 40 ft (about 12 m)spacing between vertical portions of legs 624 and 626, about 200 ft(about 61 m) is needed to allow bend of leg 624 to intercept leg 626.Coupling two legs may require a thinner contacting section 642 thancoupling three or more legs in the contacting section.

FIG. 86 depicts an embodiment for coupling legs 624 and 626 incontacting section 642. Heating elements 630 are coupled to contactingelements 632 at or near junction of contacting section 642 andhydrocarbon layer 460. Contacting elements 632 may be copper or anothersuitable electrical conductor. In certain embodiments, contactingelement 632 in leg 626 is a liner with opening 710. Contacting element632 from leg 624 passes through opening 710. Contactor 640 is coupled tothe end of contacting element 632 from leg 624. Contactor 640 provideselectrical coupling between contacting elements in legs 624 and 626.

In certain embodiments, contacting elements 632 include one or more finsor projections. The fins or projections may increase an electricalcontact area of contacting elements 632. In some embodiments, contactingelement 632 of leg 626 has an opening or other orifice that allows thecontacting element of 624 to couple to the contacting element of leg626.

In certain embodiments, legs 624 and 626 are coupled together to form adiad. Three diads may be coupled to a three-phase transformer to powerthe legs of the heaters. FIG. 87 depicts an embodiment of three diadscoupled to a three-phase transformer. In certain embodiments,transformer 634 is a delta three-phase transformer. Diad 712A includeslegs 624A and 626A. Diad 712B includes legs 624B and 626B. Diad 712Cincludes legs 624C and 626C. Diads 712A, 712B, 712C are coupled to thesecondaries of transformer 634. Diad 712A is coupled to the “A”secondary Diad 712B is coupled to the “B” secondary. Diad 712C iscoupled to the “C” secondary.

Coupling the diads to the secondaries of the delta three-phasetransformer isolates the diads from ground. Isolating the diads fromground inhibits leakage to the formation from the diads. Coupling thediads to different phases of the delta three-phase transformer alsoinhibits leakage between the heating legs of the diads in the formation.

In some embodiments, diads are used for treating formations usingtriangular or hexagonal heater patterns. FIG. 88 depicts an embodimentof groups of diads in a hexagonal pattern. Heaters may be placed at thevertices of each of the hexagons in the hexagonal pattern. Each group714 of diads (enclosed by dashed circles) may be coupled to a separatethree-phase transformer. “A”, “B”, and “C” inside groups 714 representeach diad (for example, diads 712A, 712B, 712C depicted in FIG. 87) thatis coupled to each of the three secondary phases of the transformer witheach phase coupled to one diad (with the heaters at the vertices of thehexagon). The numbers “1”, “2”, and “3” inside the hexagons representthe three repeating types of hexagons in the pattern depicted in FIG.88.

FIG. 89 depicts an embodiment of diads in a triangular pattern. Threediads 712A, 712B, 712C may be enclosed in each group 714 of diads(enclosed by dashed rectangles). Each group 714 may be coupled to aseparate three-phase transformer.

In certain embodiments, exposed metal heating elements are used insubstantially horizontal sections of u-shaped wellbores. Substantiallyu-shaped wellbores may be used in tar sands formations, oil shaleformation, or other formations with relatively thin hydrocarbon layers.Tar sands or thin oil shale formations may have thin shallow layers thatare more easily and uniformly heated using heaters placed insubstantially u-shaped wellbores. Substantially u-shaped wellbores mayalso be used to process formations with thick hydrocarbon layers informations. In some embodiments, substantially u-shaped wellbores areused to access rich layers in a thick hydrocarbon formation.

Heaters in substantially u-shaped wellbores may have long lengthscompared to heaters in vertical wellbores because horizontal heatingsections do not have problems with creep or hanging stress encounteredwith vertical heating elements. Substantially u-shaped wellbores maymake use of natural seals in the formation and/or the limited thicknessof the hydrocarbon layer. For example, the wellbores may be placed aboveor below natural seals in the formation without punching large numbersof holes in the natural seals, as would be needed with verticallyoriented wellbores. Using substantially u-shaped wellbores instead ofvertical wellbores may also reduce the number of wells needed to treat asurface footprint of the formation. Using less wells reduces capitalcosts for equipment and reduces the environmental impact of treating theformation by reducing the amount of wellbores on the surface and theamount of equipment on the surface. Substantially u-shaped wellbores mayalso utilize a lower ratio of overburden section to heated section thanvertical wellbores.

Substantially u-shaped wellbores may allow for flexible placement ofopening of the wellbores on the surface. Openings to the wellbores maybe placed according to the surface topology of the formation. In certainembodiments, the openings of wellbores are placed at geographicallyaccessible locations such as topological highs (for examples, hills).For example, the wellbore may have a first opening on a first topologichigh and a second opening on a second topologic high and the wellborecrosses beneath a topologic low (for example, a valley with alluvialfill) between the first and second topologic highs. This placement ofthe openings may avoid placing openings or equipment in topologic lowsor other inaccessible locations. In addition, the water level may not beartesian in topologically high areas. Wellbores may be drilled so thatthe openings are not located near environmentally sensitive areas suchas, but not limited to, streams, nesting areas, or animal refuges.

FIG. 90 depicts a cross-sectional representation of an embodiment of aheater with an exposed metal heating element placed in a substantiallyu-shaped wellbore. Heaters 716A, 716B, 716C have first end portions atfirst location 646 on surface 534 of the formation and second endportions at second location 650 on the surface. Heaters 716A, 716B, 716Chave sections 718 in overburden 458. Sections 718 are configured toprovide little or no heat output. In certain embodiments, sections 718include an insulated electrical conductor such as insulated copper.Sections 718 are coupled to heating elements 630.

In certain embodiments, portions of heating elements 630 aresubstantially parallel in hydrocarbon layer 460. In certain embodiments,heating elements 630 are exposed metal heating elements. In certainembodiments, heating elements 630 are exposed metal temperature limitedheating elements. Heating elements 630 may include ferromagneticmaterials such as 9% by weight to 13% by weight chromium stainless steellike 410 stainless steel, chromium stainless steels such as T/P91 orT/P92, 409 stainless steel, VM12 (Vallourec and Mannesmann Tubes,France) or iron-cobalt alloys for use as temperature limited heaters. Insome embodiments, heating elements 630 are composite temperature limitedheating elements such as 410 stainless steel and copper compositeheating elements or 347H, iron, copper composite heating elements.Heating elements 630 may have lengths of at least about 100 m, at leastabout 500 m, or at least about 1000 m, up to lengths of about 6000 m.

Heating elements 630 may be solid rods or tubulars. In certainembodiments, solid rod heating elements have diameters several times theskin depth at the Curie temperature of the ferromagnetic material.Typically, the solid rod heating elements may have diameters of 1.91 cmor larger (for example, 2.5 cm, 3.2 cm, 3.81 cm, or 5.1 cm). In certainembodiments, tubular heating elements have wall thicknesses of at leasttwice the skin depth at the Curie temperature of the ferromagneticmaterial. Typically, the tubular heating elements have outside diametersof between about 2.5 cm and about 15.2 cm and wall thickness in rangebetween about 0.13 cm and about 1.01 cm.

In certain embodiments, tubular heating elements 630 allow fluids to beconvected through the tubular heating elements. Fluid flowing throughthe tubular heating elements may be used to preheat the tubular heatingelements, to initially heat the formation, and/or to recover heat fromthe formation after heating is completed for the in situ heat treatmentprocess. Fluids that may flow through the tubular heating elementsinclude, but are not limited to, air, water, steam, helium, carbondioxide or other fluids. In some embodiments, a hot fluid, such ascarbon dioxide or helium, flows through the tubular heating elements toprovide heat to the formation. The hot fluid may be used to provide heatto the formation before electrical heating is used to provide heat tothe formation. In some embodiments, the hot fluid is used to provideheat in addition to electrical heating. Using the hot fluid to provideheat to the formation in addition to providing electrical heating may beless expensive than using electrical heating alone to provide heat tothe formation. In some embodiments, water and/or steam flows through thetubular heating element to recover heat from the formation. The heatedwater and/or steam may be used for solution mining and/or otherprocesses.

Transition sections 720 may couple heating elements 630 to sections 718.In certain embodiments, transition sections 720 include material thathas a high electrical conductivity but is corrosion resistant, such as347 stainless steel over copper. In an embodiment, transition sectionsinclude a composite of stainless steel clad over copper. Transitionsections 720 inhibit overheating of copper and/or insulation in sections718.

FIG. 91 depicts a representational top view of an embodiment of asurface pattern of heaters depicted in FIG. 90. Heaters 716A-L may bearranged in a repeating triangular pattern on the surface of theformation, as shown in FIG. 91. A triangle may be formed by heaters716A, 716B, and 716C and a triangle formed by heaters 716C, 716D, and716E. In some embodiments, heaters 716A-L are arranged in a straightline on the surface of the formation. Heaters 716A-L have first endportions at first location 646 on the surface and second end portions atsecond location 650 on the surface. Heaters 716A-L are arranged suchthat (a) the patterns at first location 646 and second location 650correspond to each other, (b) the spacing between heaters is maintainedat the two locations on the surface, and/or (c) the heaters all havesubstantially the same length (substantially the same horizontaldistance between the end portions of the heaters on the surface as shownin the top view of FIG. 91).

As depicted in FIGS. 90 and 91, cables 722, 724 may be coupled totransformer 728 and one or more heater units, such as the heater unitincluding heaters 716A, 716B, 716C. Cables 722, 724 may carry a largeamount of power. In certain embodiments, cables 722, 724 are capable ofcarrying high currents with low losses. For example, cables 722, 724 maybe thick copper or aluminum conductors. The cables may also have thickinsulation layers. In some embodiments, cable 722 and/or cable 724 maybe superconducting cables. The superconducting cables may be cooled byliquid nitrogen. Superconducting cables are available from Superpower,Inc. (Schenectady, N.Y., U.S.A.). Superconducting cables may minimizepower loss and reduce the size of the cables needed to coupletransformer 728 to the heaters. In some embodiments, cables 722, 724 maybe made of carbon nanotubes. Carbon nanotubes as conductors may haveabout 1000 times the conductivity of copper for the same diameter. Also,carbon nanotubes may not require refrigeration during use.

In certain embodiments, bus bar 726A is coupled to first end portions ofheaters 716A-L and bus bar 726B is coupled to second end portions ofheaters 716A-L. Bus bars 726A,B electrically couple heaters 716A-L tocables 722, 724 and transformer 728. Bus bars 726A,B distribute power toheaters 716A-L. In certain embodiments, bus bars 726A,B are capable ofcarrying high currents with low losses. In some embodiments, bus bars726A,B are made of superconducting material such as the superconductormaterial used in cables 722, 724. In some embodiments, bus bars 726A,Bmay include carbon nanotube conductors.

As shown in FIGS. 90 and 91, heaters 716A-L are coupled to a singletransformer 728. In certain embodiments, transformer 728 is a source oftime-varying current. In certain embodiments, transformer 728 is anelectrically isolated, single-phase transformer. In certain embodiments,transformer 728 provides power to heaters 716A-L from an isolatedsecondary phase of the transformer. First end portions of heaters 716A-Lmay be coupled to one side of transformer 728 while second end portionsof the heaters are coupled to the opposite side of the transformer.Transformer 728 provides a substantially common voltage to the first endportions of heaters 716A-L and a substantially common voltage to thesecond end portions of heaters 716A-L. In certain embodiments,transformer 728 applies a voltage potential to the first end portions ofheaters 716A-L that is opposite in polarity and substantially equal inmagnitude to a voltage potential applied to the second end portions ofthe heaters. For example, a +660 V potential may be applied to the firstend portions of heaters 716A-L and a −660 V potential applied to thesecond end portions of the heaters at a selected point on the wave oftime-varying current (such as AC or modulated DC). Thus, the voltages atthe two end portion of the heaters may be equal in magnitude andopposite in polarity with an average voltage that is substantially atground potential.

Applying the same voltage potentials to the end portions of all heaters716A-L produces voltage potentials along the lengths of the heaters thatare substantially the same along the lengths of the heaters. FIG. 92depicts a cross-sectional representation, along a vertical plane, suchas the plane A-A shown in FIG. 90, of substantially u-shaped heaters ina hydrocarbon layer. The voltage potential at the cross-sectional pointshown in FIG. 92 along the length of heater 716A is substantially thesame as the voltage potential at the corresponding cross-sectionalpoints on heaters 716A-L shown in FIG. 92. At lines equidistant betweenheater wellheads, the voltage potential is approximately zero. Otherwells, such as production wells or monitoring wells, may be locatedalong these zero voltage potential lines, if desired. Production wells206 located close to the overburden may be used to transport formationfluid that is initially in a vapor phase to the surface. Productionwells located close to a bottom of the heated portion of the formationmay be used to transport formation fluid that is initially in a liquidphase to the surface.

In certain embodiments, the voltage potential at the midpoint of heaters716A-L is about zero. Having similar voltage potentials along thelengths of heaters 716A-L inhibits current leakage between the heaters.Thus, there is little or no current flow in the formation and theheaters may have long lengths as described above. Having the oppositepolarity and substantially equal voltage potentials at the end portionsof the heaters also halves the voltage applied at either end portion ofthe heater versus having one end portion of the heater grounded and oneend portion at full potential. Reducing (halving) the voltage potentialapplied to an end portion of the heater generally reduces currentleakage, reduces insulator requirements, and/or reduces arcing distancesbecause of the lower voltage potential to ground applied at the endportions of the heaters.

In certain embodiments, substantially vertical heaters are used toprovide heat to the formation. Opposite polarity and substantially equalvoltage potentials, as described above, may be applied to the endportions of the substantially vertical heaters. FIG. 93 depicts aside-view representation of substantially vertical heaters coupled to asubstantially horizontal wellbore. Heaters 716A, 716B, 716C, 716D, 716E,716F are located substantially vertical in hydrocarbon layer 460. Firstend portions of heaters 716A, 716B, 716C, 716D, 716E, 716F are coupledto bus bar 726A on a surface of the formation. Second end portions ofheaters 716A, 716B, 716C, 716D, 716E, 716F are coupled to bus bar 726Bin contacting section 642.

Bus bar 726B may be a bus bar located in a substantially horizontalwellbore in contacting section 642. Second end portions of heaters 716A,716B, 716C, 716D, 716E, 716F may be coupled to bus bar 726B by anymethod described herein or any method known in the art. For example,containers with thermite powder are coupled to bus bar 726B (forexample, by welding or brazing the containers to the bus bar), endportions of heaters 716A, 716B, 716C, 716D, 716E, 716F are placed insidethe containers, and the thermite powder is activated to electricallycouple the heaters to the bus bar. The containers may be coupled to busbar 726B by, for example, placing the containers in holes or recesses inbus bar 726B or coupled to the outside of the bus bar and then brazingor welding the containers to the bus bar.

Bus bar 726A and bus bar 726B may be coupled to transformer 728 withcables 722, 724, as described above. Transformer 728 may providevoltages to bar 726A and bus bar 726B as described above for theembodiments depicted in FIGS. 90 and 91. For example, transformer 728may apply a voltage potential to the first end portions of heaters716A-F that is opposite in polarity and substantially equal in magnitudeto a voltage potential applied to the second end portions of theheaters. Applying the same voltage potentials to the end portions of allheaters 716A-F may produce voltage potentials along the lengths of theheaters that are substantially the same along the lengths of theheaters. Applying the same voltage potentials to the end portions of allheaters 716A-F may inhibit current leakage between the heaters and/orinto the formation.

In certain embodiments, it may be advantageous to allow some currentleakage into the formation during early stages of heating to heat theformation at a faster rate. Current leakage from the heaters into theformation electrically heats the formation directly. The formation isheated by direct electrical heating in addition to conductive heatprovided by the heaters. The formation (the hydrocarbon layer) may havean initial electrical resistance that averages at least 10 ohm·m. Insome embodiments, the formation has an initial electrical resistance ofat least 100 ohm·m or of at least 300 ohm·m. Direct electrical heatingis achieved by having opposite potentials applied to adjacent heaters inthe hydrocarbon layer. Current may be allowed to leak into the formationuntil a selected temperature is reached in the heaters or in theformation. The selected temperature may be below or near the temperaturethat water proximate one or more heaters boils off. After water boilsoff, the hydrocarbon layer is substantially electrically isolated fromthe heaters and direct heating of the formation is inefficient. Afterthe selected temperature is reached, the voltage potential is applied inthe opposite polarity and substantially equal magnitude manner describedabove for FIGS. 90 and 91 so that adjacent heaters will have the samevoltage potential along their lengths.

Current is allowed to leak into the formation by reversing the polarityof one or more heaters shown in FIG. 91 so that a first group of heatershas a positive voltage potential at first location 646 and a secondgroup of heaters has a negative voltage potential at the first location.The first end portions, at first location 646, of a first group ofheaters (for example, heaters 716A, 716B, 716D, 716E, 716G, 716H, 716J,716K, depicted in FIG. 91) are applied with a positive voltage potentialthat is substantially equal in magnitude to a negative voltage potentialapplied to the second end portions, at second location 650, of the firstgroup of heaters. The first end portions, at first location 646, of thesecond group of heaters (for example, heaters 716C, 716F, 716I, 716L)are applied with a negative voltage potential that is substantiallyequal in magnitude to the positive voltage potential applied to thefirst end portions of the first group of heaters. Similarly, the secondend portions, at second location 650, of the second group of heaters areapplied with a positive voltage potential substantially equal inmagnitude to the negative potential applied to the second end portionsof the first group of heaters. After the selected temperature isreached, the first end portions of both groups of heaters are appliedwith voltage potential that is opposite in polarity and substantiallysimilar in magnitude to the voltage potential applied to the second endportions of both groups of heaters.

In some embodiments, the heating elements have thin electricallyinsulating layer, described above, to inhibit current leakage from theheating elements. In some embodiments, the thin electrically insulatinglayer is aluminum oxide or thermal spray coated aluminum oxide. In someembodiments, the thin electrically insulating layer is an enamel coatingof a ceramic composition. The thin electrically insulating layer mayinhibit heating elements of a three-phase heater from leaking currentbetween the elements, from leaking current into the formation, and fromleaking current to other heaters in the formation. Thus, the three-phaseheater may have a longer heater length.

In certain embodiments, a heater is electrically isolated from theformation because the heater has little or no voltage potential on theoutside of the heater. FIG. 94 depicts an embodiment of a substantiallyu-shaped heater that electrically isolates itself from the formation.Heater 716 has a first end portion at a first opening on surface 534 anda second end portion at a second opening on the surface. In someembodiments, heater 716 has only the first end portion at the surfacewith the second end of the heater located in hydrocarbon layer 460 (theheater is a single-ended heater). FIGS. 95 and 96 depict embodiments ofsingle-ended heaters that electrically isolate themselves from theformation. In certain embodiments, single-ended heater 716 has anelongated portion that is substantially horizontal in hydrocarbon layer460, as shown in FIGS. 95 and 96. In some embodiments, single-endedheater 716 has an elongated portion with an orientation other thansubstantially horizontal in hydrocarbon layer 460. For example, thesingle-ended heater may have an elongated portion that is oriented 15°off horizontal in the hydrocarbon layer.

As shown in FIGS. 94-96, heater 716 includes heating element 630 locatedin hydrocarbon layer 460. Heating element 630 may be a ferromagneticconduit heating element or ferromagnetic tubular heating element. Incertain embodiments, heating element 630 is a temperature limited heatertubular heating element. In certain embodiments, heating element 630 isa 9% by weight to 13% by weight chromium stainless steel tubular such asa 410 stainless steel tubular, a T/P91 stainless steel tubular, or aT/P92 stainless steel tubular. In certain embodiments, heating element630 includes ferromagnetic material with a wall thickness of at leastabout one skin depth of the ferromagnetic material at 25° C. In someembodiments, heating element 630 includes ferromagnetic material with awall thickness of at least about two times the skin depth of theferromagnetic material at 25° C., at least about three times the skindepth of the ferromagnetic material at 25° C., or at least about fourtimes the skin depth of the ferromagnetic material at 25° C.

Heating element 630 is coupled to one or more sections 718. Sections 718are located in overburden 458. Sections 718 include higher electricalconductivity materials such as copper or aluminum. In certainembodiments, sections 718 are copper clad inside carbon steel.

Center conductor 730 is positioned inside heating element 630. In someembodiments, heating element 630 and center conductor 730 are placed orinstalled in the formation by unspooling the heating element and thecenter conductor from one or more spools while they are placed into theformation. In some embodiments, heating element 630 and center conductor730 are coupled together on a single spool and unspooled as a singlesystem with the center conductor inside the heating element. In someembodiments, heating element 630 and center conductor 730 are located onseparate spools and the center conductor is positioned inside theheating element after the heating element is placed in the formation.

In certain embodiments, center conductor 730 is located at or near acenter of heating element 630. Center conductor 730 may be substantiallyelectrically isolated from heating element 630 along a length of thecenter conductor (for example, the length of the center conductor inhydrocarbon layer 460). In certain embodiments, center conductor 730 isseparated from heating element 630 by one or moreelectrically-insulating centralizers. The centralizers may includesilicon nitride or another electrically insulating material. Thecentralizers may inhibit electrical contact between center conductor 730and heating element 630 so that, for example, arcing or shorting betweenthe center conductor and the heating element is inhibited. In someembodiments, center conductor 730 is a conductor (for example, a solidconductor or a tubular conductor) so that the heater is in aconductor-in-conduit configuration.

In certain embodiments, center conductor 730 is a copper rod or coppertubular. In some embodiments, center conductor 730 and/or heatingelement 630 has a thin electrically insulating layer to inhibit currentleakage from the heating elements. In some embodiments, the thinelectrically insulating layer is aluminum oxide or thermal spray coatedaluminum oxide. In some embodiments, the thin electrically insulatinglayer is an enamel coating of a ceramic composition. The thinelectrically insulating layer may inhibit heating elements of athree-phase heater from leaking current between the elements, fromleaking current into the formation, and from leaking current to otherheaters in the formation. Thus, the three-phase heater may have a longerheater length.

In certain embodiments, center conductor 730 is an insulated conductor.The insulated conductor may include an electrically conductive coreinside an electrically conductive sheath with electrical insulationbetween the core and the sheath. In certain embodiments, the insulatedconductor includes a copper core inside a non-ferromagnetic stainlesssteel (for example, 347 stainless steel) sheath with magnesium oxideinsulation between the core and the sheath. The core may be used toconduct electrical current through the insulated conductor. In someembodiments, the insulated conductor is placed inside heating element630 without centralizers or spacers between the insulated conductor andthe heating element. The sheath and the electrical insulation of theinsulated conductor may electrically insulate the core from heatingelement 630 if the center conductor and the heating element touch. Thus,the core and heating element 630 are inhibited from electricallyshorting to each other. The insulated conductor or another solid centerconductor 730 may be inhibited from being crushed or deformed by heatingelement 630. In certain embodiments, one end portion of center conductor730 is electrically coupled to one end portion of heating element 630 atsurface 534 using electrical coupling 732, as shown in FIG. 94. In someembodiments, the end of center conductor 730 is electrically coupled tothe end of heating element 630 in hydrocarbon layer 460 using electricalcoupling 732, as shown in FIGS. 95 and 96. Thus, center conductor 730 iselectrically coupled to heating element 630 in a series configuration inthe embodiments depicted in FIGS. 94-96. In certain embodiments, centerconductor 730 is the insulated conductor and the core of the insulatedconductor is electrically coupled to heating element 630 in the seriesconfiguration. Center conductor 730 is a return electrical conductor forheating element 630 so that current in the center conductor flows in anopposite direction from current in the heating element (as representedby arrows 734). The electromagnetic field generated by current flow incenter conductor 730 substantially confines the flow of electrons andheat generation to the inside of heating element 630 (for example, theinside wall of the heating element) below the Curie temperature of theferromagnetic material in the heating element. Thus, the outside ofheating element 630 is at substantially zero potential and the heatingelement is electrically isolated from the formation and any adjacentheater or heating element at temperatures below the Curie temperature ofthe ferromagnetic material (for example, at 25° C.). Having the outsideof heating element 630 at substantially zero potential and the heatingelement electrically isolated from the formation and any adjacent heateror heating element allows for long length heaters to be used inhydrocarbon layer 460 without significant electrical (current) losses tothe hydrocarbon layer. For example, heaters with lengths of at leastabout 100 m, at least about 500 m, or at least about 1000 m may be usedin hydrocarbon layer 460.

During application of electrical current to heating element 630 andcenter conductor 730, heat is generated by the heater. In certainembodiments, heating element 630 generates a majority or all of the heatoutput of the heater. For example, when electrical current flows throughferromagnetic material in heating element 630 and copper or another lowresistivity material in center conductor 730, the heating elementgenerates a majority or all of the heat output of the heater. Generatinga majority of the heat in the outer conductor (heating element 630)instead of center conductor 730 may increase the efficiency of heattransfer to the formation by allowing direct heat transfer from the heatgenerating element (heating element 630) to the formation and may reduceheat losses across heater 716 (for example, heat losses between thecenter conductor and the outer conductor if the center conductor is theheat generating element). Generating heat in heating element 630 insteadof center conductor 730 also increases the heat generating surface areaof heater 716. Thus, for the same operating temperature of heater 716,more heat can be provided to the formation using the outer conductor(heating element 630) as the heat generating element rather than centerconductor 730.

In some embodiments, a fluid flows through heater 716 (represented byarrows 736 in FIGS. 94 and 95) to preheat the formation and/or torecover heat from the heating element. In the embodiment depicted inFIG. 94, fluid flows from one end of heater 716 to the other end of theheater inside and through heating element 630 and outside centerconductor 730, as shown by arrows 736. In the embodiment depicted inFIG. 95, fluid flows into heater 716 through center conductor 730, whichis a tubular conductor, as shown by arrows 736. Center conductor 730includes openings 738 at the end of the center conductor to allow fluidto exit the center conductor. Openings 738 may be perforations or otherorifices that allow fluid to flow into and/or out of center conductor730. Fluid then returns to the surface inside heating element 630 andoutside center conductor 730, as shown by arrows 736.

Fluid flowing inside heater 716 (represented by arrows 736 in FIGS. 94and 95) may be used to preheat the heater, to initially heat theformation, and/or to recover heat from the formation after heating iscompleted for the in situ heat treatment process. Fluids that may flowthrough the heater include, but are not limited to, air, water, steam,helium, carbon dioxide or other high heat capacity fluids. In someembodiments, a hot fluid, such as carbon dioxide, helium, or DOWTHERM®(The Dow Chemical Company, Midland, Mich., U.S.A.), flows through thetubular heating elements to provide heat to the formation. The hot fluidmay be used to provide heat to the formation before electrical heatingis used to provide heat to the formation. In some embodiments, the hotfluid is used to provide heat in addition to electrical heating. Usingthe hot fluid to provide heat to or preheat the formation in addition toproviding electrical heating may be less expensive than using electricalheating alone to provide heat to the formation. In some embodiments,water and/or steam flows through the tubular heating element to recoverheat from the formation after in situ heat treatment of the formation.The heated water and/or steam may be used for solution mining and/orother processes.

FIGS. 97A and 97B depict an embodiment for using substantially u-shapedwellbores to time sequence heat two layers in a hydrocarbon containingformation. In FIG. 97A, substantially horizontal opening 522A is formedin hydrocarbon layer 460A extending from relatively vertical openings522. Hydrocarbon layer 460A is separated from hydrocarbon layer 460B byimpermeable zone 740. In certain embodiments, hydrocarbon layer 460B isan upper layer or lesser depth layer than hydrocarbon layer 460A.Impermeable zone 740 provides a substantially impermeable seal for fluidflow between hydrocarbon layer 460A and hydrocarbon layer 460B. Incertain embodiments (for example, in an oil shale formation),hydrocarbon layer 460A has a higher richness than hydrocarbon layer460B.

Heating element 630A is placed in opening 522A in hydrocarbon layer460A. Overburden casing 530 is placed along the relatively verticalwalls of openings 522 in hydrocarbon layer 460B. Overburden casing 530inhibits heat transfer to hydrocarbon layer 460B while heat is providedto hydrocarbon layer 460A by heating element 630A. Heating element 630Ais used to provide heat to hydrocarbon layer 460A. Formation fluids,such as pyrolyzed hydrocarbons, may be produced from hydrocarbon layer460A.

Heat may be provided to hydrocarbon layer 460A by heating element 630Afor a selected length of time. The selected length of time may be basedon a variety of factors including, but not limited to, formationcharacteristics, present or future economic factors, or capital costs.For example, for an oil shale formation, hydrocarbon layer 460A may havea richness of about 0.12 L/kg (30.5 gals/ton) so the layer is heated forabout 25 years. Production of formation fluids from hydrocarbon layer460A may continue from the layer until production slows down to anuneconomical rate.

After hydrocarbon layer 460A is heated for the selected time, heatingelement 630A is turned off. Heating element 630A may be pulled firmly(for example, yanked) upwards so that the heating element breaks off atlinks 742. Links 742 may be weak links designed to pull apart when aselected or sufficient amount of pulling force is applied to the links.The upper portions of heating element 630A are then pulled out of theformation and the substantially horizontal portion of heating element630A is left in opening 522A, as shown in FIG. 97B. In some embodiments,only one link 742 may be broken so that the upper portion above the onelink can be removed and the remaining portions of the heater can beremoved by pulling on the opposite end of the heater. Thus, the entirelength of heating element 630A may be removed from the formation.

After upper portions of heating element 630A are removed from openings522, plugs 744 may be placed into openings 522 at a selected location inhydrocarbon layer 460B, as depicted in FIG. 97B. In certain embodiments,plugs 744 are placed into openings 522 at or near impermeable zone 740.Packing 532 may be placed into openings 522 above plugs 744. In someembodiments, packing 532 is filled into openings 522 without plugs inthe openings.

After plugs 744 and/or packing 532 is set into place in openings 522,substantially horizontal opening 522B may be formed in hydrocarbon layer460B through casing 530. Heating element 630B is placed into opening522B. Heating element 630B is used to provide heat to hydrocarbon layer460B. Formation fluids, such as pyrolyzed hydrocarbons, may be producedfrom hydrocarbon layer 460B.

Heating hydrocarbon layers 460A, 460B in the time-sequenced mannerdescribed above may be more economical than producing from only onelayer or using vertical heaters to provide heat to the layerssimultaneously. Using relatively vertical openings 522 to access bothhydrocarbon layers at different times may save on capital costsassociated with forming openings in the formation and providing surfacefacilities to power the heating elements. Heating hydrocarbon layer 460Afirst before heating hydrocarbon layer 460B may improve the economics oftreating the formation (for example, the net present value of a projectto treat the formation). In addition, impermeable zone 740 and packing532 may provide a seal for hydrocarbon layer 460A after heating andproduction from the layer. This seal may be useful for abandonment ofthe hydrocarbon layer after treating the hydrocarbon layer.

In certain embodiments, portions of the wellbore that extend through theoverburden include casings. The casings may include materials thatinhibit inductive effects in the casings. Inhibiting inductive effectsin the casings may inhibit induced currents in the casing and/or reduceheat losses to the overburden. In some embodiments, the overburdencasings may include non-metallic materials such as fiberglass,polyvinylchloride (PVC), chlorinated PVC (CPVC), high-densitypolyethylene (HDPE), or other high temperature plastics. HDPEs withworking temperatures in a usable range include HDPEs available from DowChemical Co., Inc. (Midland, Mich., U.S.A.). The overburden casings maybe made of materials that are spoolable so that the overburden casingscan be spooled into the wellbore. In some embodiments, overburdencasings may include non-magnetic metals such as aluminum or non-magneticalloys such as manganese steels having at least 10% manganese, ironaluminum alloys with at least 18% aluminum, or austentitic stainlesssteels such as 304 stainless steel or 316 stainless steel. In someembodiments, overburden casings may include carbon steel or otherferromagnetic material coupled on the inside diameter to a highlyconductive non-ferromagnetic metal (for example, copper or aluminum) toinhibit inductive effects or skin effects. In some embodiments,overburden casings are made of inexpensive materials that may left inthe formation (sacrificial casings).

In certain embodiments, wellheads for the wellbores may be made of oneor more non-ferromagnetic materials. The wellheads may includefiberglass, PVC, CPVC, HDPE, and/or non-magnetic alloys or metals. Usingnon-ferromagnetic materials in the wellhead may inhibit undesiredheating of components in the wellhead. Ferromagnetic materials used inthe wellhead may be electrically and/or thermally insulated from othercomponents of the wellhead. In some embodiments, an inert gas (forexample, nitrogen or argon) is purged inside the wellhead and/or insideof casings to inhibit reflux of heated gases into the wellhead and/orthe casings.

In some embodiments, ferromagnetic materials in the wellhead areelectrically coupled to a non-ferromagnetic material (for example,copper) to inhibit skin effect heat generation in the ferromagneticmaterials in the wellhead. The non-ferromagnetic material is inelectrical contact with the ferromagnetic material so that current flowsthrough the non-ferromagnetic material. For example, copper may beplasma sprayed, coated, or lined on the inside and/or outside walls ofthe wellhead. In some embodiments, a non-ferromagnetic material such ascopper is welded, brazed, clad, or otherwise electrically coupled to theinside and/or outside walls of the wellhead. For example, copper may beswaged out to line the inside walls in the wellhead. Copper may beliquid nitrogen cooled and then allowed to expand to contact and swageagainst the inside walls of the wellhead. In some embodiments, thecopper is hydraulically expanded to contact against the inside walls ofthe wellhead.

In some embodiments, two or more substantially horizontal wellbores arebranched off of a first substantially vertical wellbore drilleddownwards from a first location on a surface of the formation. Thesubstantially horizontal wellbores may be substantially parallel througha hydrocarbon layer. The substantially horizontal wellbores mayreconnect at a second substantially vertical wellbore drilled downwardsat a second location on the surface of the formation. Having multiplewellbores branching off of a single substantially vertical wellboredrilled downwards from the surface reduces the number of openings madeat the surface of the formation.

In certain embodiments, a temperature limited heater is utilized forheavy oil applications (for example, treatment of relatively permeableformations or tar sands formations). A temperature limited heater mayprovide a relatively low Curie temperature so that a maximum averageoperating temperature of the heater is less than 350° C., 300° C., 250°C., 225° C., 200° C., or 150° C. In an embodiment (for example, for atar sands formation), a maximum temperature of the heater is less thanabout 250° C. to inhibit olefin generation and production of othercracked products. In some embodiments, a maximum temperature of theheater above about 250° C. is used to produce lighter hydrocarbonproducts. For example, the maximum temperature of the heater may be ator less than about 500° C.

A heater may heat a volume of formation adjacent to a productionwellbore (a near production wellbore region) so that the temperature offluid in the production wellbore and in the volume adjacent to theproduction wellbore is less than the temperature that causes degradationof the fluid. The heat source may be located in the production wellboreor near the production wellbore. In some embodiments, the heat source isa temperature limited heater. In some embodiments, two or more heatsources may supply heat to the volume. Heat from the heat source mayreduce the viscosity of crude oil in or near the production wellbore. Insome embodiments, heat from the heat source mobilizes fluids in or nearthe production wellbore and/or enhances the radial flow of fluids to theproduction wellbore. In some embodiments, reducing the viscosity ofcrude oil allows or enhances gas lifting of heavy oil (approximately atmost 10° API gravity oil) or intermediate gravity oil (approximately 12°to 20° API gravity oil) from the production wellbore. In certainembodiments, the initial API gravity of oil in the formation is at most10°, at most 20°, at most 25°, or at most 30°. In certain embodiments,the viscosity of oil in the formation is at least 0.05 Pa·s (50 cp). Insome embodiments, the viscosity of oil in the formation is at least 0.10Pa·s (100 cp), at least 0.15 Pa·s (150 cp), or at least at least 0.20Pa·s (200 cp). Large amounts of natural gas may have to be utilized toprovide gas lift of oil with viscosities above 0.05 Pa·s. Reducing theviscosity of oil at or near the production wellbore in the formation toa viscosity of 0.05 Pa·s (50 cp), 0.03 Pa·s (30 cp), 0.02 Pa·s (20 cp),0.01 Pa·s (10 cp), or less (down to 0.001 Pa·s (1 cp) or lower) lowersthe amount of natural gas needed to lift oil from the formation. In someembodiments, reduced viscosity oil is produced by other methods such aspumping.

The rate of production of oil from the formation may be increased byraising the temperature at or near a production wellbore to reduce theviscosity of the oil in the formation in and adjacent to the productionwellbore. In certain embodiments, the rate of production of oil from theformation is increased by 2 times, 3 times, 4 times, or greater up to 20times over standard cold production, which has no external heating offormation during production. Certain formations may be more economicallyviable for enhanced oil production using the heating of the nearproduction wellbore region. Formations that have a cold production rateapproximately between 0.05 m³/(day per meter of wellbore length) and0.20 m³/(day per meter of wellbore length) may have significantimprovements in production rate using heating to reduce the viscosity inthe near production wellbore region. In some formations, productionwells up to 775 m, up to 1000 m, or up to 1500 m in length are used. Forexample, production wells between 450 m and 775 m in length are used,between 550 m and 800 m are used, or between 650 m and 900 m are used.Thus, a significant increase in production is achievable in someformations. Heating the near production wellbore region may be used informations where the cold production rate is not between 0.05 m³/(dayper meter of wellbore length) and 0.20 m³/(day per meter of wellborelength), but heating such formations may not be as economicallyfavorable. Higher cold production rates may not be significantlyincreased by heating the near wellbore region, while lower productionrates may not be increased to an economically useful value.

Using the temperature limited heater to reduce the viscosity of oil ator near the production well inhibits problems associated withnon-temperature limited heaters and heating the oil in the formation dueto hot spots. One possible problem is that non-temperature limitedheaters can cause coking of oil at or near the production well if theheater overheats the oil because the heaters are at too high atemperature. Higher temperatures in the production well may also causebrine to boil in the well, which may lead to scale formation in thewell. Non-temperature limited heaters that reach higher temperatures mayalso cause damage to other wellbore components (for example, screensused for sand control, pumps, or valves). Hot spots may be caused byportions of the formation expanding against or collapsing on the heater.In some embodiments, the heater (either the temperature limited heateror another type of non-temperature limited heater) has sections that arelower because of sagging over long heater distances. These lowersections may sit in heavy oil or bitumen that collects in lower portionsof the wellbore. At these lower sections, the heater may develop hotspots due to coking of the heavy oil or bitumen. A standardnon-temperature limited heater may overheat at these hot spots, thusproducing a non-uniform amount of heat along the length of the heater.Using the temperature limited heater may inhibit overheating of theheater at hot spots or lower sections and provide more uniform heatingalong the length of the wellbore.

In some embodiments, oil or bitumen cokes in a perforated liner orscreen in a heater/production wellbore (for example, coke may formbetween the heater and the liner or between the liner and theformation). Oil or bitumen may also coke in a toe section of a heel andtoe heater/production wellbore, as shown in and described below for FIG.112. A temperature limited heater may limit a temperature of aheater/production wellbore below a coking temperature to inhibit cokingin the well so that the wellbore does not plug up.

In certain embodiments, fluids in the relatively permeable formationcontaining heavy hydrocarbons are produced with little or nopyrolyzation of hydrocarbons in the formation. In certain embodiments,the relatively permeable formation containing heavy hydrocarbons is atar sands formation. For example, the formation may be a tar sandsformation such as the Athabasca tar sands formation in Alberta, Canadaor a carbonate formation such as the Grosmont carbonate formation inAlberta, Canada. The fluids produced from the formation are mobilizedfluids. Producing mobilized fluids may be more economical than producingpyrolyzed fluids from the tar sands formation. Producing mobilizedfluids may also increase the total amount of hydrocarbons produced fromthe tar sands formation.

FIGS. 98-101 depict side view representations of embodiments forproducing mobilized fluids from tar sands formations. In FIGS. 98-101,heaters 716 have substantially horizontal heating sections inhydrocarbon layer 460 (as shown, the heaters have heating sections thatgo into and out of the page). FIG. 98 depicts a side view representationof an embodiment for producing mobilized fluids from a tar sandsformation with a relatively thin hydrocarbon layer. FIG. 99 depicts aside view representation of an embodiment for producing mobilized fluidsfrom a thicker hydrocarbon layer (the hydrocarbon layer depicted in FIG.99 is thicker than the hydrocarbon layer depicted in FIG. 98). FIG. 100depicts a side view representation of an embodiment for producingmobilized fluids from an even thicker hydrocarbon layer (the hydrocarbonlayer depicted in FIG. 100 is thicker than the hydrocarbon layerdepicted in FIG. 99). FIG. 101 depicts a side view representation of anembodiment for producing mobilized fluids from a tar sands formationwith a hydrocarbon layer that has a shale break.

In FIG. 98, heaters 716 are placed in an alternating triangular patternin hydrocarbon layer 460. In FIGS. 99, 100, and 101, heaters 716 areplaced in an alternating triangular. pattern in hydrocarbon layer 460that repeats vertic to encompass a majority or all of the hydrocarbonlayer. In FIG. 101, the alternating triangular pattern of heaters 716 inhydrocarbon layer 460 repeats uninterrupted across shale break 746. InFIGS. 98-101, heaters 716 may be equidistantly spaced from each other.In the embodiments depicted in FIGS. 98-101, the number of vertical rowsof heaters 716 depends on factors such as, but not limited to, thedesired spacing between the heaters, the thickness of hydrocarbon layer460, and/or the number and location of shale breaks 746. In someembodiments, heaters 716 are arranged in other patterns. For example,heaters 716 may be arranged in patterns such as, but not limited to,hexagonal patterns, square patterns, or rectangular patterns.

In the embodiments depicted in FIGS. 98-101, heaters 716 provide heatthat mobilizes hydrocarbons (reduces the viscosity of the hydrocarbons)in hydrocarbon layer 460. In certain embodiments, heaters 716 provideheat that reduces the viscosity of the hydrocarbons in hydrocarbon layer460 below about 0.50 Pa·s (500 cp), below about 0.10 Pa·s (100 cp), orbelow about 0.05 Pa·s (50 cp). The spacing between heaters 716 and/orthe heat output of the heaters may be designed and/or controlled toreduce the viscosity of the hydrocarbons in hydrocarbon layer 460 todesirable values. Heat provided by heaters 716 may be controlled so thatlittle or no pyrolyzation occurs in hydrocarbon layer 460. Superpositionof heat between the heaters may create one or more drainage paths (forexample, paths for flow of fluids) between the heaters. In certainembodiments, production wells 206A and/or production wells 206B arelocated proximate heaters 716 so that heat from the heaters superimposesover the production wells. The superimposition of heat from heaters 716over production wells 206A and/or production wells 206B creates one ormore drainage paths from the heaters to the production wells. In certainembodiments, one or more of the drainage paths converge. For example,the drainage paths may converge at or near a bottommost heater and/orthe drainage paths may converge at or near production wells 206A and/orproduction wells 206B. Fluids mobilized in hydrocarbon layer 460 tend toflow towards the bottommost heaters 716, production wells 206A and/orproduction wells 206B in the hydrocarbon layer because of gravity andthe heat and pressure gradients established by the heaters and/or theproduction wells. The drainage paths and/or the converged drainage pathsallow production wells 206A and/or production wells 206B to collectmobilized fluids in hydrocarbon layer 460.

In certain embodiments, hydrocarbon layer 460 has sufficientpermeability to allow mobilized fluids to drain to production wells 206Aand/or production wells 206B. For example, hydrocarbon layer 460 mayhave a permeability of at least about 0.1 darcy, at least about 1 darcy,at least about 10 darcy, or at least about 100 darcy. In someembodiments, hydrocarbon layer 460 has a relatively large verticalpermeability to horizontal permeability ratio (K_(v)/K_(h)). Forexample, hydrocarbon layer 460 may have a K_(v)/K_(h) ratio betweenabout 0.01 and about 2, between about 0.1 and about 1, or between about0.3 and about 0.7.

In certain embodiments, fluids are produced through production wells206A located near heaters 716 in the lower portion of hydrocarbon layer460. In some embodiments, fluids are produced through production wells206B located below and approximately midway between heaters 716 in thelower portion of hydrocarbon layer 460. At least a portion of productionwells 206A and/or production wells 206B may be oriented substantiallyhorizontal in hydrocarbon layer 460 (as shown in FIGS. 98-101, theproduction wells have horizontal portions that go into and out of thepage). Production wells 206A and/or 206B may be located proximate lowerportion heaters 716 or the bottommost heaters.

In some embodiments, production wells 206A are positioned substantiallyvertically below the bottommost heaters in hydrocarbon layer 460.Production wells 206A may be located below heaters 716 at the bottomvertex of a pattern of the heaters (for example, at the bottom vertex ofthe triangular pattern of heaters depicted in FIGS. 98-101). Locatingproduction wells 206A substantially vertically below the bottommostheaters may provide efficient collection of mobilized fluids inhydrocarbon layer 460.

In certain embodiments, the bottommost heaters are located between about2 m and about 10 m from the bottom of hydrocarbon layer 460, betweenabout 4 m and about 8 m from the bottom of the hydrocarbon layer, orbetween about 5 m and about 7 m from the bottom of the hydrocarbonlayer. In certain embodiments, production wells 206A and/or productionwells 206B are located at a distance from the bottommost heaters 716that allows heat from the heaters to superimpose over the productionwells but at a distance from the heaters that inhibits coking at theproduction wells. Production wells 206A and/or production wells 206B maybe located a distance from the nearest heater (for example, thebottommost heater) of at most ¾ of the spacing between heaters in thepattern of heaters (for example, the triangular pattern of heatersdepicted in FIGS. 98-101). In some embodiments, production wells 206Aand/or production wells 206B are located a distance from the nearestheater of at most ⅔, at most ½, or at most ⅓ of the spacing betweenheaters in the pattern of heaters. In certain embodiments, productionwells 206A and/or production wells 206B are located between about 2 mand about 10 m from the bottommost heaters, between about 4 m and about8 m from the bottommost heaters, or between about 5 m and about 7 m fromthe bottommost heaters. Production wells 206A and/or production wells206B may be located between about 0.5 m and about 8 m from the bottom ofhydrocarbon layer 460, between about 1 m and about 5 m from the bottomof the hydrocarbon layer, or between about 2 m and about 4 m from thebottom of the hydrocarbon layer.

In some embodiments, at least some production wells 206A are locatedsubstantially vertically below heaters 716 near shale break 746, asdepicted in FIG. 101. Production wells 206A may be located betweenheaters 716 and shale break 746 to produce fluids that flow and collectabove the shale break. Shale break 746 may be an impermeable barrier inhydrocarbon layer 460. In some embodiments, shale break 746 has athickness between about 1 m and about 6 m, between about 2 m and about 5m, or between about 3 m and about 4 m. Production wells 206A betweenheaters 716 and shale break 746 may produce fluids from the upperportion of hydrocarbon layer 460 (above the shale break) and productionwells 206A below the bottommost heaters in the hydrocarbon layer mayproduce fluids from the lower portion of the hydrocarbon layer (belowthe shale break), as depicted in FIG. 101. In some embodiments, two ormore shale breaks may exist in a hydrocarbon layer. In such anembodiment, production wells are placed at or near each of the shalebreaks to produce fluids flowing and collecting above the shale breaks.

In some embodiments, shale break 746 breaks down (is desiccated) as theshale break is heated by heaters 716 on either side of the shale break.As shale break 746 breaks down, the permeability of the shale breakincreases and the shale break allows fluids to flow through the shalebreak. Once fluids are able to flow through shale break 746, productionwells above the shale break may not be needed for production as fluidscan flow to production wells at or near the bottom of hydrocarbon layer460 and be produced there.

In certain embodiments, the bottommost heaters above shale break 746 arelocated between about 2 m and about 10 m from the shale break, betweenabout 4 m and about 8 m from the bottom of the shale break, or betweenabout 5 m and about 7 m from the shale break. Production wells 206A maybe located between about 2 m and about 10 m from the bottommost heatersabove shale break 746, between about 4 m and about 8 m from thebottommost heaters above the shale break, or between about 5 m and about7 m from the bottommost heaters above the shale break. Production wells206A may be located between about 0.5 m and about 8 m from shale break746, between about 1 m and about 5 m from the shale break, or betweenabout 2 m and about 4 m from the shale break.

In some embodiments, heat is provided in production wells 206A and/orproduction wells 206B, depicted in FIGS. 98-101. Providing heat inproduction wells 206A and/or production wells 206B may maintain and/orenhance the mobility of the fluids in the production wells. Heatprovided in production wells 206A and/or production wells 206B maysuperpose with heat from heaters 716 to create the flow path from theheaters to the production wells. In some embodiments, production wells206A and/or production wells 206B include a pump to remove fluids to thesurface of the formation. In some embodiments, the viscosity of fluids(oil) in production wells 206A and/or production wells 206B is loweredusing heaters and/or diluent injection (for example, using a conduit inthe production wells for injecting the diluent).

In certain embodiments, in situ heat treatment of the relativelypermeable formation containing hydrocarbons (for example, the tar sandsformation) includes heating the formation to visbreaking temperatures.For example, the formation may be heated to temperatures between about100° C. and 260° C., between about 150° C. and about 250° C., or betweenabout 200° C. and about 240° C. At visbreaking temperatures, fluids inthe formation have a reduced viscosity (versus their initial viscosityat ambient formation temperature) that allows fluids to flow in theformation. The visbroken fluids may have low API gravities (for example,at most about 10°, about 12°, or about 15° API gravity).

In some embodiments, heaters in the formation are operated at full poweroutput to heat the formation to visbreaking temperatures. Operating atfull power may rapidly increase the pressure in the formation. Incertain embodiments, fluids are produced from the formation to maintaina pressure in the formation below a selected pressure as the temperatureof the formation increases to visbreaking temperatures. In someembodiments, the selected pressure is a fracture pressure of theformation. In certain embodiments, the selected pressure is betweenabout 1000 kPa and about 15000 kPa, between about 2000 kPa and about10000 kPa, or between about 2500 kPa and about 5000 kPa. The fluidsproduced from the formation may be visbroken and/or mobilized fluids.Maintaining the pressure as close to the fracture pressure as possiblemay minimize the number of production wells needed for producing fluidsfrom the formation because fluids are more mobile at higher pressures.

In certain embodiments, after the formation reaches visbreakingtemperatures, the pressure in the formation is reduced. The pressure maybe reduced by producing fluids (for example, visbroken fluids and/ormobilized fluids) from the formation. In some embodiments, the pressureis reduced below a pressure at which fluids coke in the formation toinhibit coking at pyrolysis temperatures. For example, the pressure isreduced to a pressure below about 1000 kPa, below about 800 kPa, orbelow about 700 kPa. The pressure may be reduced to inhibit coking ofasphaltenes or other large hydrocarbons in the formation. In someembodiments, the pressure may be maintained below a pressure at whichwater passes through a liquid phase at downhole (formation) temperaturesto inhibit liquid water and dolomite reactions. After reducing thepressure in the formation, the temperature may be increased to pyrolysistemperatures to begin pyrolyzation and/or upgrading of fluids in theformation. The pyrolyzed and/or upgraded fluids may be produced from theformation.

The amount of fluids produced at temperatures below visbreakingtemperatures, the amount of fluids produced at visbreaking temperatures,and the amount of upgraded fluids produced may be varied to control thequality and amount of fluids produced from the formation and the totalrecovery of hydrocarbons from the formation. For example, producing morefluid during the early stages of treatment (for example, producing attemperatures below visbreaking temperatures) may increase the totalrecovery of hydrocarbons from the formation while reducing the overallquality (lowering the overall API gravity) of fluid produced from theformation. The overall quality is reduced because more heavyhydrocarbons are produced by producing more fluids at the lowertemperatures. Producing less fluids at the lower temperatures mayincrease the overall quality of the fluids produced from the formationbut may lower the total recovery of hydrocarbons from the formation.

In certain embodiments, the formation is heated using isolated cells ofheaters (cells or sections of the formation that are not interconnectedfor fluid flow). The isolated cells may be created by using largerheater spacings in the formation. For example, large heater spacings maybe used in the embodiments depicted in FIGS. 98-101. These isolatedcells may be produced during early stages of heating (for example, attemperatures below visbreaking temperatures). Because the cells areisolated from other cells in the formation, the pressures in theisolated cells are high and more liquids are producible from theisolated cells. Thus, more liquids may be produced from the formationand a higher total recovery of hydrocarbons may be reached. During laterstages of heating, the heat gradient will interconnect the isolatedcells and pressures in the formation will drop.

In certain embodiments, the heat gradient in the formation is modifiedso that a gas cap is created at or near an upper portion of thehydrocarbon layer. For example, the heat gradient made by heaters 716depicted in the embodiments depicted in FIGS. 98-101 may be modified tocreate the gas cap at or near overburden 458 of hydrocarbon layer 460.The gas cap may push or drive liquids to the bottom of the hydrocarbonlayer so that more liquids may be produced from the formation.

In certain embodiments, fluids produced at temperatures belowvisbreaking temperatures and/or fluids produced at visbreakingtemperatures are blended with diluent to produce fluids with lowerviscosities. In some embodiments, the diluent includes upgraded orpyrolyzed fluids produced from the formation. In some embodiments, thediluent includes upgraded or pyrolyzed fluids produced from anotherportion of the formation or another formation. In certain embodiments,the amount of fluids produced at temperatures below visbreakingtemperatures and/or fluids produced at visbreaking temperatures that areblended with upgraded fluids from the formation is adjusted to create afluid suitable for transportation and/or use in a refinery. The amountof blending may be adjusted so that the fluid has chemical and physicalstability. Maintaining the chemical and physical stability of the fluidmay allow the fluid to be transported, reduce pre-treatment processes ata refinery and/or reduce or eliminate the need for adjusting therefinery process to compensate for the fluid.

In certain embodiments, formation conditions (for example, pressure andtemperature) and/or fluid production are controlled to produce fluidswith selected properties. For example, formation conditions and/or fluidproduction may be controlled to produce fluids with a selected APIgravity and/or a selected viscosity. The selected API gravity and/orselected viscosity may be produced by combining fluids produced atdifferent formation conditions (for example, combining fluids producedat different temperatures during the treatment as described above). Asan example, formation conditions and/or fluid production may becontrolled to produce fluids with an API gravity of about 19° and aviscosity of about 0.35 Pa·s (350 cp) at 19° C.

In some embodiments, formation conditions and/or fluid production iscontrolled so that water (for example, connate water) is recondensed inthe treatment area. Recondensing water in the treatment area keeps theheat of condensation in the formation. In addition, having liquid waterin the formation may increase mobility of liquid hydrocarbons (oil) inthe formation. Liquid water may wet rock or other strata in theformation by occupying pores or corners in the strata and creating aslick surface that moves liquid hydrocarbons more readily through theformation.

In certain embodiments, a drive process (for example, a steam injectionprocess such as cyclic steam injection, a steam assisted gravitydrainage process (SAGD), a solvent injection process, or a carbondioxide injection process) is used to treat the tar sands formation inaddition to the in situ heat treatment process. In some embodiments,heaters are used to create high permeability zones (or injection zones)in the formation for the drive process. Heaters may be used to create amobilization geometry or production network in the formation to allowfluids to flow through the formation during the drive process. Forexample, heaters may be used to create drainage paths between theheaters and production wells for the drive process. In some embodiments,the heaters are used to provide heat during the drive process. Theamount of heat provided by the heaters may be small compared to the heatinput from the drive process (for example, the heat input from steaminjection).

In some embodiments, the in situ heat treatment process may provide lessheat to the formation (for example, use a wider heat spacing) if the insitu heat treatment process is followed by the drive process. The driveprocess may be used to increase the amount of heat provided to theformation to compensate for the loss of heat injection.

In some embodiments, the drive process is used to treat the formationand produce hydrocarbons from the formation. The drive process mayrecover a low amount of oil in place from the formation (for example,less than 20% recovery of oil in place from the formation). The in situheat treatment process may be used following the drive process toincrease the recovery of oil in place from the formation. In someembodiments, the drive process preheats the formation for the in situheat treatment process. In some embodiments, the formation is treatedusing the in situ heat treatment process a significant time after theformation has been treated using the drive process. For example, the insitu heat treatment process is used 1 year, 2 years, or 3 years after aformation has been treated using the drive process. The in situ heattreatment process may be used on formations that have been left dormantafter the drive process treatment because further hydrocarbon productionusing the drive process is not possible and/or not economically feasibleon the formation. In some embodiments, the formation remains at leastsomewhat preheated from the drive process even after the significanttime.

In some embodiments, heaters are used to preheat the formation for thedrive process. For example, heaters may be used to create injectivity inthe formation for a drive fluid. The heaters may create highpermeability zones (or injection zones) in the formation for the driveprocess. In certain embodiments, heaters are used to create injectivityin formations with little or no initial injectivity (for example,karsted formations such as the Grosmont formation in Alberta, Canada).Heating the formation may create a mobilization geometry or productionnetwork in the formation to allow fluids to flow through the formationfor the drive process. For example, heaters may be used to create afluid production network between a horizontal heater and a verticalproduction well. The heaters used to preheat the formation for the driveprocess may also be used to provide heat during the drive process.

FIG. 102 depicts a top view representation of an embodiment forpreheating using heaters for the drive process. Injection wells 748 andproduction wells 206 are substantially vertical wells. Heaters 716 arelong substantially horizontal heaters positioned so that the heaterspass in the vicinity of injection wells 748. Heaters 716 intersect thevertical well patterns slightly displaced from the vertical rows.

The vertical location of heaters 716 with respect to injection wells 748and production wells 206 depends on, for example, the verticalpermeability of the formation. In formations with at least some verticalpermeability, injected steam will rise to the top of the permeable layerin the formation. In such formations, heaters 716 may be located nearthe bottom of hydrocarbon layer 460, as shown in FIG. 103. In formationswith very low vertical permeabilities, more than one horizontal heatermay be used with the heaters stacked substantially vertically or withheaters at varying depths in the hydrocarbon layer (for example, heaterpatterns as shown in FIGS. 98-101). The vertical spacing between thehorizontal heaters in such formations may correspond to the distancebetween the heaters and the injection wells. Heaters 716 are located inthe vicinity of injection wells 748 and/or production wells 206 so thatsufficient energy is delivered by the heaters to provide flow rates forthe drive process that are economically viable. The spacing betweenheaters 716 and injection wells 748 or production wells 206 may bevaried to provide an economically viable drive process. The amount ofpreheating may also be varied to provide an economically viable process.

Some embodiments of formations with little or no initial injectivity(such as karsted formations or karsted layers in formations) may havetight vugs in one or more layers of the formations. The tight vugs maybe vugs filled with viscous fluids such as bitumen or heavy oil. In someembodiments, the vugs have a porosity of at least about 20 porosityunits, at least about 30 porosity units, or at least about 35 porosityunits. The formation may have a porosity of at most about 15 porosityunits, at most about 10 porosity units, or at most about 5 porosityunits. The tight vugs inhibit steam or other fluids from being injectedinto the formation or the layers with tight vugs. In certainembodiments, the karsted formation or karsted layers of the formationare treated using the in situ heat treatment process. Heating of theseformations or layers may decrease the viscosity of the fluids in thetight vugs and allow the fluids to drain (for example, mobilize thefluids).

In certain embodiments, only the karsted layers of the formation aretreated using the in situ heat treatment process. Other non-karstedlayers of the formation may be used as seals for the in situ heattreatment process. For example, in the Grosmont formation, the Grosmont3 layer may be used as a bottom seal for in situ heat treatment of theNisku and upper Ireton layers.

In some embodiments, the drive process is used after the in situ heattreatment of the karsted formation or karsted layers. In someembodiments, heaters are used to preheat the karsted formation orkarsted layers to create injectivity in the formation.

In certain embodiments, the karsted formation or karsted layers areheated to temperatures below the decomposition temperature of rock (forexample, dolomite) in the formation (for example, temperatures at mostabout 407° C.). In some embodiments, the karsted formation or karstedlayers are heated to temperatures above the decomposition temperature ofdolomite in the formation. At temperatures above the dolomitedecomposition temperature, the dolomite may decompose to produce carbondioxide. The decomposition of the dolomite and the carbon dioxideproduction may create permeability in the formation and mobilize viscousfluids in the formation. In some embodiments, the produced carbondioxide is maintained in the formation to produce a gas cap in theformation. The carbon dioxide may be allowed to rise to the upperportions of the karsted layers to produce the gas cap.

In some embodiments, heaters are used to produce and/or maintain the gascap in the formation for the in situ heat treatment process and/or thedrive process. The gas cap may drive fluids from upper portions to lowerportions of the formation and/or from portions of the formation towardsportions of the formation at lower pressures (for example, portions withproduction wells). In some embodiments, little or no heating is providedin the portions of the formation with the gas cap. In some embodiments,heaters in the gas cap are turned down and/or off after formation of thegas cap. Using less heating in the gas cap may reduce the energy inputinto the formation and increase the efficiency of the in situ heattreatment process and/or the drive process. In some embodiments,production wells and/or heater wells that are located in the gas capportion of the formation may be used for injection of fluid (forexample, steam) to maintain the gas cap.

In some embodiments, the production front of the drive process followsbehind the heat front of the in situ heat treatment process. In someembodiments, areas behind the production front are further heated toproduce more fluids from the formation. Further heating behind theproduction front may also maintain the gas cap behind the productionfront and/or maintain quality in the production front of the driveprocess.

In certain embodiments, the drive process is used before the in situheat treatment of the formation. In some embodiments, the drive processis used to mobilize fluids in a first section of the formation. Themobilized fluids may then be pushed into a second section by heating thefirst section with heaters. Fluids may be produced from the secondsection. In some embodiments, the fluids in the second section arepyrolyzed and/or upgraded using the heaters.

In some embodiments, the drive process is used to create a “gas cushion”or pressure sink before the in situ heat treatment process in formationswith low permeabilities. The gas cushion may be created by fracturingthe formation during the drive process. The gas cushion may inhibitpressures from increasing to quickly to fracture pressure during the insitu heat treatment process. The gas cushion may provide a path forgases to escape or travel during early stages of heating during the insitu heat treatment process.

In some embodiments, the drive process (for example, the steam injectionprocess) is used to mobilize fluids before the in situ heat treatmentprocess. Steam injection may be used to get hydrocarbons (oil) away fromrock or other strata in the formation. The steam injection may mobilizethe oil without heating the rock.

In some embodiments, injection of a fluid (for example, steam or carbondioxide) may consume heat in the formation and cool the formationdepending on the pressure in the formation. In some embodiments, theinjected fluid is used to recover heat from the formation. The recoveredheat may be used in surface processing of fluids and/or to preheat otherportions of the formation using the drive process.

FIG. 104 depicts a representation of an embodiment for producinghydrocarbons from a hydrocarbon containing formation (for example, a tarsands formation). Hydrocarbon layer 460 includes one or more portionswith heavy hydrocarbons. Hydrocarbons may be produced from hydrocarbonlayer 460 using more than one process. In certain embodiments,hydrocarbons are produced from a first portion of hydrocarbon layer 460using a steam injection process (for example, cyclic steam injection orsteam-assisted gravity drainage) and a second portion of the hydrocarbonlayer using an in situ heat treatment process. In the steam injectionprocess, steam is injected into the first portion of hydrocarbon layer460 through injection well 748. First hydrocarbons are produced from thefirst portion through production well 206A. The first hydrocarbonsinclude hydrocarbons mobilized by the injection of steam. In certainembodiments, the first hydrocarbons have an API gravity of at most 15°,at most 10°, at most 8°, or at most 6°.

Heaters 716 are used to heat the second portion of hydrocarbon layer 460to mobilization, visbreaking, and/or pyrolysis temperatures. Secondhydrocarbons are produced from the second portion through productionwell 206B. In some embodiments, the second hydrocarbons include at leastsome pyrolyzed hydrocarbons. In certain embodiments, the secondhydrocarbons have an API gravity of at least 15°, at least 20°, or atleast 25°.

In some embodiments, the first portion of hydrocarbon layer 460 istreated using heaters after the steam injection process. Heaters may beused to increase the temperature of the first portion and/or treat thefirst portion using an in situ heat treatment process. Secondhydrocarbons (including at least some pyrolyzed hydrocarbons) may beproduced from the first portion through production well 206A.

In some embodiments, the second portion of hydrocarbon layer 460 istreated using the steam injection process before using heaters 716 totreat the second portion. The steam injection process may be used toproduce some fluids (for example, first hydrocarbons or hydrocarbonsmobilized by the steam injection) through production well 206B from thesecond portion and/or preheat the second portion before using heaters716. In some embodiments, the steam injection process may be used afterusing heaters 716 to treat the first portion and/or the second portion.

Producing hydrocarbons through both processes increases the totalrecovery of hydrocarbons from hydrocarbon layer 460 and may be moreeconomical than using either process alone. In some embodiments, thefirst portion is treated with the in situ heat treatment process afterthe steam injection process is completed. For example, after the steaminjection process no longer produces viable amounts of hydrocarbon fromthe first portion, the in situ heat treatment process may be used on thefirst portion.

Steam is provided to injection well 748 from facility 750 via conduit749. Facility 750 is a steam and electricity cogeneration facility.Facility 750 may burn hydrocarbons in generators to make electricity.Facility 750 may burn gaseous and/or liquid hydrocarbons to makeelectricity. The electricity generated is used to provide electricalpower for heaters 716 via line 751. Waste heat from the generators isused to make steam. In some embodiments, some of the hydrocarbonsproduced from the formation are used to provide gas for heaters 716, ifthe heaters utilize gas to provide heat to the formation. The amount ofelectricity and steam generated by facility 750 may be controlled tovary the production rate and/or quality of hydrocarbons produced fromthe first portion and/or the second portion of hydrocarbon layer 460.The production rate and/or quality of hydrocarbons produced from thefirst portion and/or the second portion may be varied to produce aselected API gravity in a mixture made by blending the firsthydrocarbons with the second hydrocarbons. The first hydrocarbon and thesecond hydrocarbons may be blended after production to produce theselected API gravity. The production from the first portion and/or thesecond portion may be varied in response to changes in the marketplacefor either first hydrocarbons, second hydrocarbons, and/or a mixture ofthe first and second hydrocarbons.

First hydrocarbons produced from production well 206A and provided tofacility 750 via conduit 753 and/or second hydrocarbons produced fromproduction well 206B and provided to facility 750 via conduit 755 may beused as fuel for facility 750. First hydrocarbons produced fromproduction well 206A may be provided to injection well via conduit 757.Second hydrocarbons produced from production well 206B may be providedto injection well 748 via conduit 759. In some embodiments, firsthydrocarbons and/or second hydrocarbons are treated (for example,removing undesirable products) before being used as fuel for facility750. The amount of first hydrocarbons and second hydrocarbons used asfuel for facility 750 may be determined, for example, by economics forthe overall process, the marketplace for either first or secondhydrocarbons, availability of treatment facilities for either first orsecond hydrocarbons, and/or transportation facilities available foreither first or second hydrocarbons. In some embodiments, most or allthe hydrocarbon gas produced from hydrocarbon layer 460 is used as fuelfor facility 750. Burning all the hydrocarbon gas in facility 750eliminates the need for treatment and/or transportation of gasesproduced from hydrocarbon layer 460.

The produced first hydrocarbons and the second hydrocarbons may betreated and/or blended in facility 752. First hydrocarbons produced fromproduction well 206A may be provided to facility 752 via conduit 761and/or second hydrocarbons produced from production well 206B may beprovided to facility 752 via conduit 763. In some embodiments, the firstand second hydrocarbons are blended to make a mixture that istransportable through a pipeline. In some embodiments, the first andsecond hydrocarbons are blended to make a mixture that is useable as afeedstock for a refinery. The amount of first and second hydrocarbonsproduced may be varied based on changes in the requirements fortreatment and/or blending of the hydrocarbons. In some embodiments,treated hydrocarbons are provided from blending facility 752 to facility750 via conduit 765. The treated hydrocarbons are used in facility 750.

FIG. 105 depicts an embodiment for heating and producing from theformation with the temperature limited heater in a production wellbore.Production conduit 754 is located in wellbore 756. In certainembodiments, a portion of wellbore 756 is located substantiallyhorizontally in formation 758. In some embodiments, the wellbore islocated substantially vertically in the formation. In an embodiment,wellbore 756 is an open wellbore (an uncased wellbore). In someembodiments, the wellbore has a casing or liner with perforations oropenings to allow fluid to flow into the wellbore.

Conduit 754 may be made from carbon steel or more corrosion resistantmaterials such as stainless steel. Conduit 754 may include apparatus andmechanisms for gas lifting or pumping produced oil to the surface. Forexample, conduit 754 includes gas lift valves used in a gas liftprocess. Examples of gas lift control systems and valves are disclosedin U.S. Pat. No. 6,715,550 to Vinegar et al. and U.S. Patent ApplicationPublication Nos. 2002-0036085 to Bass et al. and 2003-0038734 to Hirschet al., each of which is incorporated by reference as if fully set forthherein. Conduit 754 may include one or more openings (perforations) toallow fluid to flow into the production conduit. In certain embodiments,the openings in conduit 754 are in a portion of the conduit that remainsbelow the liquid level in wellbore 756. For example, the openings are ina horizontal portion of conduit 754.

Heater 760 is located in conduit 754, as shown in FIG. 105. In someembodiments, heater 760 is located outside conduit 754, as shown in FIG.106. The heater located outside the production conduit may be coupled(strapped) to the production conduit. In some embodiments, more than oneheater (for example, two, three, or four heaters) are placed aboutconduit 754. The use of more than one heater may reduce bowing orflexing of the production conduit caused by heating on only one side ofthe production conduit. In an embodiment, heater 760 is a temperaturelimited heater. Heater 760 provides heat to reduce the viscosity offluid (such as oil or hydrocarbons) in and near wellbore 756. In certainembodiments, heater 760 raises the temperature of the fluid in wellbore756 up to a temperature of 250° C. or less (for example, 225° C., 200°C., or 150° C.). Heater 760 may be at higher temperatures (for example,275° C., 300° C., or 325° C.) because the heater provides heat toconduit 754 and there is some temperature differential between theheater and the conduit. Thus, heat produced from the heater does notraise the temperature of fluids in the wellbore above 250° C.

In certain embodiments, heater 760 includes ferromagnetic materials suchas Carpenter Temperature Compensator “32”, Alloy 42-6, Alloy 52, Invar36, or other iron-nickel or iron-nickel-chromium alloys. In certainembodiments, nickel or nickel-chromium alloys are used in heater 760. Insome embodiments, heater 760 includes a composite conductor with a morehighly conductive material such as copper on the inside of the heater toimprove the turndown ratio of the heater. Heat from heater 760 heatsfluids in or near wellbore 756 to reduce the viscosity of the fluids andincrease a production rate through conduit 754.

In certain embodiments, portions of heater 760 above the liquid level inwellbore 756 (such as the vertical portion of the wellbore depicted inFIGS. 105 and 106) have a lower maximum temperature than portions of theheater located below the liquid level. For example, portions of heater760 above the liquid level in wellbore 756 may have a maximumtemperature of 100° C. while portions of the heater located below theliquid level have a maximum temperature of 250° C. In certainembodiments, such a heater includes two or more ferromagnetic sectionswith different Curie temperatures to achieve the desired heatingpattern. Providing less heat to portions of wellbore 756 above theliquid level and closer to the surface may save energy.

In certain embodiments, heater 760 is electrically isolated on theheater's outside surface and allowed to move freely in conduit 754. Insome embodiments, electrically insulating centralizers are placed on theoutside of heater 760 to maintain a gap between conduit 754 and theheater.

In some embodiments, heater 760 is cycled (turned on and off) so thatfluids produced through conduit 754 are not overheated. In anembodiment, heater 760 is turned on for a specified amount of time untila temperature of fluids in or near wellbore 756 reaches a desiredtemperature (for example, the maximum temperature of the heater). Duringthe heating time (for example, 10 days, 20 days, or 30 days), productionthrough conduit 754 may be stopped to allow fluids in the formation to“soak” and obtain a reduced viscosity. After heating is turned off orreduced, production through conduit 754 is started and fluids from theformation are produced without excess heat being provided to the fluids.During production, fluids in or near wellbore 756 will cool down withoutheat from heater 760 being provided. When the fluids reach a temperatureat which production significantly slows down, production is stopped andheater 760 is turned back on to reheat the fluids. This process may berepeated until a desired amount of production is reached. In someembodiments, some heat at a lower temperature is provided to maintain aflow of the produced fluids. For example, low temperature heat (forexample, 100° C., 125° C., or 150° C.) may be provided in the upperportions of wellbore 756 to keep fluids from cooling to a lowertemperature.

FIG. 107 depicts an embodiment of a heating/production assembly that maybe located in a wellbore for gas lifting. Heating/production assembly762 may be located in a wellbore in the formation (for example, wellbore756 depicted in FIGS. 105 or 106). Conduit 754 is located inside casing530. In an embodiment, conduit 754 is coiled tubing such as 6 cmdiameter coiled tubing. Casing 530 has a diameter between 10 cm and 25cm (for example, a diameter of 14 cm, 16 cm, or 18 cm). Heater 760 iscoupled to an end of conduit 754. In some embodiments, heater 760 islocated inside conduit 754. In some embodiments, heater 760 is aresistive portion of conduit 754. In some embodiments, heater 760 iscoupled to a length of conduit 754.

Opening 764 is located at or near a junction of heater 760 and conduit754. In some embodiments, opening 764 is a slot or a slit in conduit754. In some embodiments, opening 764 includes more than one opening inconduit 754. Opening 764 allows production fluids to flow into conduit754 from a wellbore. Perforated casing 766 allows fluids to flow intothe heating/production assembly 762. In certain embodiments, perforatedcasing 766 is a wire wrapped screen. In one embodiment, perforatedcasing 766 is a 9 cm diameter wire wrapped screen.

Perforated casing 766 may be coupled to casing 530 with packing material532. Packing material 532 inhibits fluids from flowing into casing 530from outside perforated casing 766. Packing material 532 may also beplaced inside casing 530 to inhibit fluids from flowing up the annulusbetween the casing and conduit 754. Seal assembly 768 is used to sealconduit 754 to packing material 532. Seal assembly 768 may fix aposition of conduit 754 along a length of a wellbore. In someembodiments, seal assembly 768 allows for unsealing of conduit 754 sothat the production conduit and heater 760 may be removed from thewellbore.

Feedthrough 770 is used to pass lead-in cable 636 to supply power toheater 760. Lead-in cable 636 may be secured to conduit 754 with clamp772. In some embodiments, lead-in cable 636 passes through packingmaterial 532 using a separate feedthrough.

A lifting gas (for example, natural gas, methane, carbon dioxide,propane, and/or nitrogen) may be provided to the annulus between conduit754 and casing 530. Valves 774 are located along a length of conduit 754to allow gas to enter the production conduit and provide for gas liftingof fluids in the production conduit. The lifting gas may mix with fluidsin conduit 754 to lower the density of the fluids and allow for gaslifting of the fluids out of the formation. In certain embodiments,valves 774 are located in or near the overburden section of theformation so that gas lifting is provided in the overburden section. Insome embodiments, fluids are produced through the annulus betweenconduit 754 and casing 530 and the lifting gas is supplied throughvalves 774.

In an embodiment, fluids are produced using a pump coupled to conduit754. The pump may be a submersible pump (for example, an electric or gaspowered submersible pump). In some embodiments, a heater is coupled toconduit 754 to maintain the reduced viscosity of fluids in the conduitand/or the pump.

In certain embodiments, an additional conduit such as an additionalcoiled tubing conduit is placed in the formation. Sensors may be placedin the additional conduit. For example, a production logging tool may beplaced in the additional conduit to identify locations of producingzones and/or to assess flow rates. In some embodiments, a temperaturesensor (for example, a distributed temperature sensor, a fiber opticsensor, and/or an array of thermocouples) is placed in the additionalconduit to determine a subsurface temperature profile.

Some embodiments of the heating/production assembly are used in a wellthat preexists (for example, the heating/production assembly isretrofitted for a preexisting production well, heater well, ormonitoring well). An example of the heating/production assembly that maybe used in the preexisting well is depicted in FIG. 108. Somepreexisting wells include a pump. The pump in the preexisting well maybe left in the heating/production well retrofitted with theheating/production assembly.

FIG. 108 depicts an embodiment of the heating/production assembly thatmay be located in the wellbore for gas lifting. In FIG. 108, conduit 754is located in outside production conduit 776. In an embodiment, outsideproduction conduit 776 is 11.4 cm diameter production tubing. Casing 530has a diameter of 24.4 cm. Perforated casing 766 has a diameter of 11.4cm. Seal assembly 768 seals conduit 754 inside outside productionconduit 776. In an embodiment, pump 778 is a jet pump such as abottomhole assembly jet pump.

FIG. 109 depicts another embodiment of a heating/production assemblythat may be located in a wellbore for gas lifting. Heater 760 is locatedinside perforated casing 766. Heater 760 is coupled to lead-in cable 636through a feedthrough in packing material 532. Production conduit 754extends through packing material 532. Pump 778 is located along conduit754. In certain embodiments, pump 778 is a jet pump or a bean pump.Valves 774 are located along conduit 754 for supplying lift gas to theconduit.

In some embodiments, heat is inhibited from transferring into conduit754. FIG. 110 depicts an embodiment of conduit 754 and heaters 760 thatinhibit heat transfer into the conduit. Heaters 760 are coupled toconduit 754. Heaters 760 include ferromagnetic sections 486 andnon-ferromagnetic sections 488. Ferromagnetic sections 486 provide heatat a temperature that reduces the viscosity of fluids in or near awellbore. Non-ferromagnetic sections 488 provide little or no heat. Incertain embodiments, ferromagnetic sections 486 and non-ferromagneticsections 488 are 6 m in length. In some embodiments, ferromagneticsections 486 and non-ferromagnetic sections 488 are between 3 m and 12 min length, between 4 m and 11 m in length, or between 5 m and 10 m inlength. In certain embodiments, non-ferromagnetic sections 488 includeperforations 780 to allow fluids to flow to conduit 754. In someembodiments, heater 760 is positioned so that perforations are notneeded to allow fluids to flow to conduit 754.

Conduit 754 may have perforations 780 to allow fluid to enter theconduit. Perforations 780 coincide with non-ferromagnetic sections 488of heater 760. Sections of conduit 754 that coincide with ferromagneticsections 486 include insulation conduit 782. Conduit 782 may be a vacuuminsulated tubular. For example, conduit 782 may be a vacuum insulatedproduction tubular available from Oil Tech Services, Inc. (Houston,Tex., U.S.A.). Conduit 782 inhibits heat transfer into conduit 754 fromferromagnetic sections 486. Limiting the heat transfer into conduit 754reduces heat loss and/or inhibits overheating of fluids in the conduit.In an embodiment, heater 760 provides heat along an entire length of theheater and conduit 754 includes conduit 782 along an entire length ofthe production conduit.

In certain embodiments, more than one wellbore 756 is used to produceheavy oils from a formation using the temperature limited heater. FIG.111 depicts an end view of an embodiment with wellbores 756 located inhydrocarbon layer 460. Portions of wellbores 756 are placedsubstantially horizontally in a triangular pattern in hydrocarbon layer460. In certain embodiments, wellbores 756 have a spacing of 30 m to 60m, 35 m to 55 m, or 40 m to 50. Wellbores 756 may include productionconduits and heaters previously described. Fluids may be heated andproduced through wellbores 756 at an increased production rate above acold production rate for the formation. Production may continue for aselected time (for example, 5 years to 10 years, 6 years to 9 years, or7 years to 8 years) until heat produced from each of wellbores 756begins to overlap (superposition of heat begins). At such a time, heatfrom lower wellbores (such as wellbores 756 near the bottom ofhydrocarbon layer 460) is continued, reduced, or turned off whileproduction is continued. Production in upper wellbores (such aswellbores 756 near the top of hydrocarbon layer 460) may be stopped sothat fluids in the hydrocarbon layer drain towards the lower wellbores.In some embodiments, power is increased to the upper wellbores and thetemperature raised above the Curie temperature to increase the heatinjection rate. Draining fluids in the formation in such a processincreases total hydrocarbon recovery from the formation.

In an embodiment, a temperature limited heater is used in a horizontalheater/production well. The temperature limited heater may provideselected amounts of heat to the “toe” and the “heel” of the horizontalportion of the well. More heat may be provided to the formation throughthe toe than through the heel, creating a “hot portion” at the toe and a“warm portion” at the heel. Formation fluids may be formed in the hotportion and produced through the warm portion, as shown in FIG. 112.

FIG. 112 depicts an embodiment of a heater well for selectively heatinga formation. Heat source 202 is placed in opening 522 in hydrocarbonlayer 460. In certain embodiments, opening 522 is a substantiallyhorizontal opening in hydrocarbon layer 460. Perforated casing 766 isplaced in opening 522. Perforated casing 766 provides support thatinhibits hydrocarbon and/or other material in hydrocarbon layer 460 fromcollapsing into opening 522. Perforations in perforated casing 766 allowfor fluid flow from hydrocarbon layer 460 into opening 522. Heat source202 may include hot portion 784. Hot portion 784 is a portion of heatsource 202 that operates at higher heat output than adjacent portions ofthe heat source. For example, hot portion 784 may output between 650 W/mand 1650 W/m, 650 W/m and 1500 W/m, or 800 W/m and 1500 W/m. Hot portion784 may extend from a “heel” of the heat source to the “toe” of the heatsource. The heel of the heat source is the portion of the heat sourceclosest to the point at which the heat source enters a hydrocarbonlayer. The toe of the heat source is the end of the heat source furthestfrom the entry of the heat source into the hydrocarbon layer.

In an embodiment, heat source 202 includes warm portion 786. Warmportion 786 is a portion of heat source 202 that operates at lower heatoutputs than hot portion 784. For example, warm portion 786 may outputbetween 30 W/m and 1000 W/m, 30 W/m and 750 W/m, or 100 W/m and 750 W/m.Warm portion 786 may be located closer to the heel of heat source 202.In certain embodiments, warm portion 786 is a transition portion (forexample, a transition conductor) between hot portion 784 and overburdenportion 788. Overburden portion 788 is located in overburden 458.Overburden portion 788 provides a lower heat output than warm portion786. For example, overburden portion 788 may output between 10 W/m and90 W/m, 15 W/m and 80 W/m, or 25 W/m and 75 W/m. In some embodiments,overburden portion 788 provides as close to no heat (0 W/m) as possibleto overburden 458. Some heat, however, may be used to maintain fluidsproduced through opening 522 in a vapor phase or at elevated temperaturein overburden 458.

In certain embodiments, hot portion 784 of heat source 202 heatshydrocarbons to high enough temperatures to result in coke 790 formingin hydrocarbon layer 460. Coke 790 may occur in an area surroundingopening 522. Warm portion 786 may be operated at lower heat outputs sothat coke does not form at or near the warm portion of heat source 202.Coke 790 may extend radially from opening 522 as heat from heat source202 transfers outward from the opening. At a certain distance, however,coke 790 no longer forms because temperatures in hydrocarbon layer 460at the certain distance will not reach coking temperatures. The distanceat which no coke forms is a function of heat output (W/m from heatsource 202), type of formation, hydrocarbon content in the formation,and/or other conditions in the formation.

The formation of coke 790 inhibits fluid flow into opening 522 throughthe coking. Fluids in the formation may, however, be produced throughopening 522 at the heel of heat source 202 (for example, at warm portion786 of the heat source) where there is little or no coke formation. Thelower temperatures at the heel of heat source 202 reduce the possibilityof increased cracking of formation fluids produced through the heel.Fluids may flow in a horizontal direction through the formation moreeasily than in a vertical direction. Typically, horizontal permeabilityin a relatively permeable formation is approximately 5 to 10 timesgreater than vertical permeability. Thus, fluids flow along the lengthof heat source 202 in a substantially horizontal direction. Producingformation fluids through opening 522 is possible at earlier times thanproducing fluids through production wells in hydrocarbon layer 460. Theearlier production times through opening 522 is possible becausetemperatures near the opening increase faster than temperatures furtheraway due to conduction of heat from heat source 202 through hydrocarbonlayer 460. Early production of formation fluids may be used to maintainlower pressures in hydrocarbon layer 460 during start-up heating of theformation. Start-up heating of the formation is the time of heatingbefore production begins at production wells in the formation. Lowerpressures in the formation may increase liquid production from theformation. In addition, producing formation fluids through opening 522may reduce the number of production wells needed in the formation.

In some embodiments, a temperature limited heater positioned in awellbore heats steam that is provided to the wellbore. The heated steammay be introduced into a portion of the formation. In certainembodiments, the heated steam may be used as a heat transfer fluid toheat a portion of the formation. In some embodiments, the steam is usedto solution mine desired minerals from the formation. In someembodiments, the temperature limited heater positioned in the wellboreheats liquid water that is introduced into a portion of the formation.

In an embodiment, the temperature limited heater includes ferromagneticmaterial with a selected Curie temperature. The use of a temperaturelimited heater may inhibit a temperature of the heater from increasingbeyond a maximum selected temperature (for example, at or about theCurie temperature). Limiting the temperature of the heater may inhibitpotential burnout of the heater. The maximum selected temperature may bea temperature selected to heat the steam to above or near 100%saturation conditions, superheated conditions, or supercriticalconditions. Using a temperature limited heater to heat the steam mayinhibit overheating of the steam in the wellbore. Steam introduced intoa formation may be used for synthesis gas production, to heat thehydrocarbon containing formation, to carry chemicals into the formation,to extract chemicals or minerals from the formation, and/or to controlheating of the formation.

A portion of the formation where steam is introduced or that is heatedwith steam may be at significant depths below the surface (for example,greater than about 1000 m, about 2500, or about 5000 m below thesurface). If steam is heated at the surface of the formation andintroduced to the formation through a wellbore, a quality of the heatedsteam provided to the wellbore at the surface may have to be relativelyhigh to accommodate heat losses to the wellbore casing and/or theoverburden as the steam travels down the wellbore. Heating the steam inthe wellbore may allow the quality of the steam to be significantlyimproved before the steam is provided to the formation. A temperaturelimited heater positioned in a lower section of the overburden and/oradjacent to a target zone of the formation may be used to controllablyheat steam to improve the quality of the steam injected into theformation and/or inhibit condensation along the length of the heater. Incertain embodiments, the temperature limited heater improves the qualityof the steam injected and/or inhibits condensation in the wellbore forlong steam injection wellbores (especially for long horizontal steaminjection wellbores).

A temperature limited heater positioned in a wellbore may be used toheat the steam to above or near 100% saturation conditions orsuperheated conditions. In some embodiments, a temperature limitedheater may heat the steam so that the steam is above or nearsupercritical conditions. The static head of fluid above the temperaturelimited heater may facilitate producing 100% saturation, superheated,and/or supercritical conditions in the steam. Supercritical or nearsupercritical steam may be used to strip hydrocarbon material and/orother materials from the formation. In certain embodiments, steamintroduced into the formation may have a high density (for example, aspecific gravity of about 0.8 or above). Increasing the density of thesteam may improve the ability of the steam to strip hydrocarbon materialand/or other materials from the formation.

Improved iron, chromium, and nickel alloys containing manganese, copperand tungsten, in combination with niobium, carbon and nitrogen, maymaintain a finer grain size despite high temperature solution annealingor processing. Such behavior may be beneficial in reducing aheat-affected-zone in welded material. Higher solution-annealingtemperatures are particularly important for achieving the best metalcarbide (MC), nanocarbide. For example, niobium carbide (NbC)nanocarbide strengthening during high-temperature creep service, andsuch effects are amplified (finer nanocarbide structures that arestable) by compositions of the improved alloys. Tubing and canisterapplications that include the composition of the improved alloys and arewrought processed result in stainless steels that may be able toage-harden during service at about 700° C. to about 800° C. Improvedalloys may be able to age-harden even more if the alloys arecold-strained prior to high-temperature service, but suchcold-prestraining is not necessary for good high temperature propertiesor age-hardening. Some prior art alloys, such as NF709 requirecold-prestraining to achieve good high temperature creep properties, andthis is a disadvantage in particular because after such alloys arewelded, the advantages of the cold-prestraining in the weld heateffected zone are lost. Cold-prestraining may degrade rather thanenhance high-temperature strength and long-term durability, andtherefore may be limited or not permitted by, for example, constructioncodes. The improved alloys described herein are suitable for lowtemperature applications, for example, cryogenic applications. Theimproved alloys which have strength and sufficient ductility attemperatures of, for example, −50° C. to −200° C., also retain strengthat higher temperatures than many alloys often used in cryogenicapplications, such as 201 LN and YUS 130, thus for services such asliquefied natural gas, where a failure may result in a fire, theimproved alloy would retain strength in the vicinity of the fire longerthan other materials.

An improved alloy composition may include, by weight: about 18% to about22% chromium, about 12% to about 13% nickel, above about 0% to about4.5% copper (and in some embodiments, above 3.0% to about 4.5% copper),about 1% to about 10% manganese, about 0.3% to about 1% silicon, about0.5% to about 1% niobium, about 0.3% to about 1% molybdenum, about 0.08%to about 0.2% carbon, about 0.2% to about 0.5% nitrogen, above 0% toabout 2% tungsten, and with the balance being essentially iron (forexample, about 47.8% to about 68.12% iron and optionally othercomponents). Such an improved alloy may be useful when processed by hotdeformation, cold deformation, and/or welding into, for example,casings, canisters, or strength members for heaters. In someembodiments, the improved alloy includes, by weight: about 20% chromium,about 3% copper, about 4% manganese, about 0.3% molybdenum, about 0.77%niobium, about 13% nickel, about 0.5% silicon, about 1% tungsten, about0.09% carbon, and about 0.26% nitrogen, with the balance beingessentially iron. In certain embodiments, the improved alloy includes,by weight: about 19% chromium, about 4.2% manganese, about 0.3%molybdenum, about 0.8% niobium, about 12.5% nickel, about 0.5% silicon,about 0.09% carbon, about 0.24% nitrogen by weight with the balancebeing iron. In some embodiments, improved alloys may vary an amount ofmanganese, amount of nickel, and/or a Mn/Ni ratio to enhance resistanceto high temperature sulfidation, increase high temperature strength,and/or reduce cost.

Improved wrought alloy compositions may include the compositionsdescribed in the preceding paragraphs, compositions disclosed in U.S.Patent Application Publication No. 2003/0056860 to Maziasz et al., whichis incorporated by reference herein or similar compositions. Theimproved wrought alloy composition may include at least 3.25% by weightprecipitates at 800° C. The improved wrought alloy composition may havebeen processed by aging or hot working and/or by cold working. As aresult of such aging or hot working and/or cold working, the improvedwrought alloy compositions (for example, NbC, Cr-rich M₂₃C₆) may containnanocarbonitrides precipitates. Such nanocarbonitride precipitates arenot known to be present in cast compositions such as those disclosed inU.S. Published Patent Application No. 2003/0056860, and are believed toformed upon hot working and/or cold working of the compositions. Thenanocarbonitride precipitates may include particles having dimensionsfrom about 5 nanometers to about 100 nanometers, from about 10nanometers to about 90 nanometers, or from about 20 to about 80nanometers. These wrought alloys may have microstructures consisting ofat least, but not limited to, nanocarbides (NbC, Cr-rich M₂₃C₆), whichform during aging (stress-free) or creep (stress <0.5 yield stress(YS)). The microstructures may be a consequence of both the native alloycomposition and the details of the wrought processing. In solutionannealed material, the concentration of such nanoscale particles may below. The nanoscale particles may be affected by solution annealtemperature/time (more and finer dispersion with longer anneal above1150° C.) and by cold- or warm-prestrain (cold work) after the solutionanneal treatment. Cold prestrain may create dislocation networks withinthe grains that may serve as nucleation sites for the nanocarbides.Solution annealed material initially has zero percent cold work.Bending, stretching, coiling, rolling or swaging may create, for example5-15% cold work. The effect of the nanocarbides on yield strength orcreep strength may be to provide strength based on dislocation-pinning,with more closely-spaced pinning sites (higher concentration, finerdispersion) providing more strength (particles are barriers to climb orglide of dislocations).

The improved wrought alloy may include nanonitrides (for example, NbCrN)in the matrix together with nanocarbides, after, for example, being agedfor 1000 hours at 800° C. The NbCr nitrides have been identified usinganalytical electron microscopy (AEM) as rich in Nb and Cr, and as thetetragonal nitride phase by electron diffraction (both carbides arecubic phases). X-ray energy dispersive quantitative analysis has shownthat for the improved alloy compositions, these nanoscale nitrideparticles may have a composition by weight of: about 63% Nb, 28% Cr, and6% Fe, with other components being less than 1.5% each. Such NbCrnitrides were not observed in aged cast stainless steels with similarcompositions, and appear to be a direct consequence of the wroughtprocessing. The mixed microstructures of nanocarbides and nanonitridesmay be responsible for the improved strength of these alloy compositionsat elevated temperatures, such as, for example, 900-1000° C.

In some embodiments, the improved alloys are processed to produce awrought material. A 6″ inside diameter, centrifugal cast pipe having awall thickness of 1.5″ may be cast from the improved alloy. A sectionmay be removed from the casting and heat treated at a temperature of atleast 1250° C. for, for example, about three hours. The heat treatedsection may be hot rolled at a temperature of at least 1200° C. to a0.75″ thickness, annealed at a temperature of at least 1200° C. forfifteen minutes, and then sandblasted. The sandblasted section may becold rolled to a thickness of about 0.55″. The cold rolled section maybe annealed at a temperature of at least 1250° C. for about an hour in,for example, air with an argon cover, and then given a final additionalheat treatment for about one hour at a temperature of at least 1250° C.in air with an argon blanket. An alternative process may include any ofthe following: initially homogenizing the cast plate at a temperature ofat least 1200° C. for about 1½ hours; hot rolling at a temperature of atleast 1200° C. to a 1″ thickness; and annealing the cold-rolled platefor about one hour at a temperature of at least 1200° C. The improvedalloys may be extruded at, for example, about 1200° C., with, forexample, a mandrel diameter of 0.9″ and a die diameter of 1.35″ toproduce good quality tubes. The wrought material may be welded by, forexample, laser welding or tungsten gas arc welding. Thus, tubes may beproduced by rolling plates and welding seams.

Annealing the improved alloys at higher temperatures, such as 1250° C.,may improve properties of the alloys. At a higher temperature, more ofthe phases go into solution and upon cooling precipitate into phasesthat contribute positively to the properties, such as high temperaturecreep and tensile strength. Annealing at temperatures higher than 1250°C., such as 1300° C. may be beneficial. For example, calculated phasepresent in the improved alloys may decrease by 0.08% at 1300° C. asopposed to the phase present in the improved alloys at 1200° C. Thus,upon cooling, more useful precipitates may form by 0.08%. Improvedalloys may have high temperature creep strengths and tensile strengthsthat are superior to conventional alloys. For example, niobiumstabilized stainless steel alloys that include manganese, nitrogen,copper and tungsten may have high temperature creep strengths andtensile strengths that are improved, or substantially improved relativeto conventional alloys such as 347H.

Improved alloys may have increased strength relative to standardstainless steel alloys such as Super 304H at high temperatures (forexample, about 700° C., about 800° C., or above 1000° C.). Superior hightemperature creep-rupture strength (for example, creep-rupture strengthat about 800° C., about 900° C. or about 1250° C.) may be improved as aresult of (a) composition, (b) stable, fine-grain microstructuresinduced by high temperature processing, and (c) age-inducedprecipitation structures in the improved alloys. Precipitationstructures include, for example, micro-carbides that strengthen grainboundaries and stable nanocarbides that strengthen inside the grains.Presence of phases other than sigma, laves, G, and chi phases contributeto high temperature properties. Stable microstructures may be achievedby proper selection of components. High temperature aging induced orcreep-induced microstructures may have minimal or no intermetallicsigma, laves and chi phases. Intermetallic sigma, lava and chi phasesmay weaken the strength properties of alloys.

At about 800° C., the improved alloys may include at least 3% or atleast 3.25% by weight of microcarbides, other phases, and/or stable,fine grain microstructure that produce strength. At about 900° C., theimproved alloys may include, by weight, at least 1.5%, at least 2%, atleast 3%, at least 3.5%, or at least 5% microcarbides, other phases,and/or stable, fine grain microstructure that produce strength. Thesevalues may be higher than the corresponding values in 347H or Super 304Hstainless steel alloys at about 900° C. At about 1250° C. improvedalloys may include at least 0.5% by weight micro-carbides, other phases,and/or stable, fine grain microstructure that produce strength. Theresulting higher weight percent of microcarbides, other phases, and/orstable, fine grain microstructure, and the exclusion of sigma and lavesphases, may account for superior high temperature performance of theimproved alloys.

Alloys having similar or superior high temperature performance to theimproved alloys may be derived by modeling phase behavior at elevatedtemperatures and selecting compositions that retain at least 1.5%, atleast 2%, or at least 2.5% by weight of phases other than sigma or lavesphases at, for example, about 900° C. For example, a stablemicrostructure may include an amount, by weight, of: niobium that isnearly ten times the amount of carbon, from about 1% to about 12%manganese, and from about 0.15 to about 0.5% of nitrogen. Copper andtungsten may be included in the composition to increase the amount ofstable microstructures. The choice of elements for the improved alloysallows processing by various methods and results in a stable, fine grainsize, even after heat treatments of at least 1250° C. Many prior artalloys tend to grain coarsen significantly when annealed at such hightemperatures whereas the improved alloy can be improved by such hightemperature treatment. In some embodiments, grain size is controlled toachieve desirable high temperature tensile and creep properties. Stablegrain structure in the improved alloys reduces grain boundary sliding,and may be a contributing factor for the better strength relative tocommercially available alloys at temperatures above, for example, about650° C.

A downhole heater assembly may include 5, 10, 20, 40, or more heaterscoupled together. For example, a heater assembly may include between 10and 40 heaters. Heaters in a downhole heater assembly may be coupled inseries. In some embodiments, heaters in a heater assembly may be spacedfrom about 7.6 m to about 30.5 m apart. For example, heaters in a heaterassembly may be spaced about 15 m apart. Spacing between heaters in aheater assembly may be a function of heat transfer from the heaters tothe formation. For example, a spacing between heaters may be chosen tolimit temperature variation along a length of a heater assembly toacceptable limits. A heater assembly may advantageously providesubstantially uniform heating over a relatively long length of anopening in a formation. Heaters in a heater assembly may include, butare not limited to, electrical heaters (for example, insulated conductorheaters, conductor-in-conduit heaters, pipe-in-pipe heaters), flamelessdistributed combustors, natural distributed combustors, and/oroxidizers. In some embodiments, heaters in a downhole heater assemblymay include only oxidizers.

FIG. 113 depicts a schematic of an embodiment of downhole oxidizerassembly 800 including oxidizers 802. In some embodiments, oxidizerassembly 800 may include oxidizers 802 and flameless distributedcombustors. Oxidizer assembly 800 may be lowered into an opening in aformation and positioned as desired. In some embodiments, a portion ofthe opening in the formation may be substantially parallel to thesurface of the Earth. In some embodiments, the opening of the formationmay be otherwise angled with respect to the surface of the Earth. In anembodiment, the opening may include a significant vertical portion and aportion otherwise angled with respect to the surface of the Earth. Incertain embodiments, the opening may be a branched opening. Oxidizerassemblies may branch from common fuel and/or oxidizer conduits in acentral portion of the opening.

Fuel 804 may be supplied to oxidizers 802 through fuel conduit 806. Insome embodiments, the fuel for the oxidizers may be hydrogen or a highhydrogen content hydrocarbon mixture. Using hydrogen as the fuel hasseveral advantages over hydrocarbon fuels. For example, hydrogen is easyto ignite, oxidizing hydrogen does not result in the generation ofcarbon dioxide or other undesired reaction products, and coking of thefuel line is eliminated.

In some embodiments, the fuel may be methane or natural gas. In someembodiments, the fuel may be a mixture of hydrocarbons produced from anin situ heat treatment process. In certain embodiments, fuel used toinitiate combustion may be enriched to decrease the temperature requiredfor ignition. In some embodiments, hydrogen (H₂) or other hydrogen richfluids may be used to enrich fuel initially supplied to the oxidizers.After ignition of the oxidizers, enrichment of the fuel may be stopped.In some embodiments, a portion or portions of fuel conduit 806 mayinclude a catalytic surface (for example, a catalytic outer surface) todecrease an ignition temperature of fuel 804.

Portions of the fuel conduit subjected to high temperatures, may includeheat shielding. The heat shielding may include an insulative underlayerand a thermally conductive overlayer. The overlayer may be a ceramiclayer. The underlayer may be a low thermal conductivity ceramic sleeveor coating. The overlayer may be a high thermal conductivity coating. Insome embodiments, the fuel line may be positioned in a conduit. Acooling flow may be circulated through the space between the fuel lineand the conduit.

Oxidizing fluid 808 may be supplied to oxidizer assembly 800 throughoxidizer conduit 810. In some embodiments, fuel conduit 806 and/oroxidizers 802 may be positioned concentrically, or substantiallyconcentrically, in oxidizer conduit 810. In some embodiments, fuelconduit 806 and/or oxidizers 802 may be arranged other thanconcentrically with respect to oxidizer conduit 810. In certain branchedopening embodiments, fuel conduit 806 and/or oxidizer conduit 810 mayhave a weld or coupling to allow placement of oxidizer assemblies 800 inbranches of the opening.

An ignition source may be positioned in or proximate oxidizers 802 toinitiate combustion. In some embodiments, an ignition source may heatthe fuel and/or the oxidizing fluid supplied to a particular heater to atemperature sufficient to support ignition of the fuel. The fuel may beoxidized with the oxidizing fluid in oxidizers 802 to generate heat.Oxidation products may mix with oxidizing fluid downstream of the firstoxidizer in oxidizer conduit 810. Exhaust gas 812 may include unreactedoxidizing fluid and unreacted fuel as well as oxidation products. Insome embodiments, a portion of exhaust gas 812 from a first oxidizer,may be provided to oxidizers 802 downstream of the first oxidizer. Insome embodiments, a portion of exhaust gas 812 may return to the surfacethrough outer conduit 814. As the exhaust gas returns to the surfacethrough outer conduit 814, heat from exhaust gas 812 may be transferredto the formation. Returning exhaust gas 812 through outer conduit 814may provide substantially uniform heating along oxidizer assembly 800due to heat from the exhaust gas integrating with the heat provided fromindividual oxidizers of the oxidizer assembly. In some embodiments,oxidizing fluid 808 may be introduced through outer conduit 814 andexhaust gas 812 may be returned through oxidizer conduit 810. In certainembodiments, heat integration may occur along an extended verticalportion of an opening.

In some embodiments, the oxidizer assembly may be a heat source used toheat water or steam. Steam produced by heat from the oxidizer assemblymay be introduced into the formation. The oxidizer assembly may beplaced in a conduit. The conduit may include critical flow orifices. Theoxidizer assembly may be started. Heat produced by the oxidizer assemblymay be used to heat water introduced into the space between the oxidizerassembly and the conduit. Steam produced from the heat may pass throughthe critical flow orifices in the conduit into the formation.

Oxidizing fluid supplied to an oxidizer assembly may include, but is notlimited to, air, oxygen enriched air, and/or hydrogen peroxide.Depletion of oxygen in oxidizing fluid may occur toward a terminal endof an oxidizer assembly. In an embodiment, a flow of oxidizing fluid maybe increased (for example, by using compression to provide excessoxidizing fluid) such that sufficient oxygen is present for operation ofthe terminal oxidizer. In some embodiments, oxidizing fluid may beenriched by increasing an oxygen content of the oxidizing fluid prior tointroduction of the oxidizing fluid to the oxidizers. Oxidizing fluidmay be enriched by methods including, but not limited to, adding oxygento the oxidizing fluid, adding an additional oxidant such as hydrogenperoxide to the oxidizing fluid (for example, air) and/or flowingoxidizing fluid through a membrane that allows preferential diffusion ofoxygen.

For oxidizers that use hydrocarbon fuel, steps may be taken to reducecoking of fuel in the fuel conduit after ignition of the oxidizers. Forexample, steam may be added to the fuel to inhibit coking in the fuelconduit. In some embodiments, the fuel may be methane that is mixed withsteam in a molar ratio of up to 1:1. In some embodiments, coking may beinhibited by decreasing a residence time of fuel in the fuel conduit. Insome embodiments, coking may be inhibited by insulating portions of thefuel conduit that pass through high temperature zones proximateoxidizers.

If steam is to be added to the fuel, the steam needs to be added at theright point. If steam is added to the fuel at the surface, the steam maycondense in the fuel line on the way down to the first oxidizer. Theresulting water may slug into the first oxidizer and flameout theoxidizer. In some embodiments, a separate water line is used tointroduce water into the fuel line. In an embodiment, the water line is¼″ tubing that transports softened water to the fuel line near the firstoxidizer. When the oxidizers are first initialized, coking preventionmay not be needed, so water is not sent through the water line. When thefirst oxidizer is hot, water may be sent through the water line to thefuel line. The water may be introduced into the fuel conduit at alocation where the temperature is about 65° C. The entrance nozzle, theheat from the first oxidizer and the velocity of the fuel in the fuelline may atomize or vaporize the water supplied to the fuel conduit.

During operation, there is enough flow through the oxidizer system toprotect the fuel line from overheating and to minimize the flametemperature. The openings of the oxidizers are designed to allow acertain flowrate through the system that increases as the bypass flowincreases. At lower bypass flows, the amount of gas is restricted andtemperatures may become elevated. At the design bypass flow, the maximumtemperatures are lower, which may result in no or low amounts of oxidesof nitrogen and a low fuel line temperature.

In some embodiments, opening sizes in the oxidizers and the fuel linepressure relative to the oxidant line pressure may be controlled tocreate a flammable mixture in each oxidizer. The composition of the fuelmay be controlled to minimize flame temperatures. The composition of thefuel may be changed by adding diluent such as, but not limited to, steamand/or nitrogen. Opening sizes, fuel line pressure and fuel compositionallow the flame region of each oxidizer to remain hot, stable andprotected from the bypass flow around the oxidizers so that theoxidizers burn out the fuel supplied to the individual oxidizers.

FIG. 114 depicts a perspective view of an embodiment of oxidizer 802 ofthe downhole heater assembly without an igniter. FIG. 115 depicts aschematic representation of oxidizer 802 with igniter 816 positioned inoxidant line 810. Oxidizer 802 may include mix chamber 818, igniterholder 820, nozzle and flame holder 822, and heat shield 824. In someembodiments, the flame area in flame holder 822 and/or heat shield 824may be at a temperature of about 1100° C. The temperature adjacent tothe oxidizer may be about 700° C. Fuel conduit 806 may pass throughoxidizer 802. Fuel conduit 806 may have one or more fuel openings 826within mix chamber 818. Openings 828 allow oxidant to flow into mixchamber 818. Opening 830 allows a portion of the igniter supported onigniter holder 820 to pass into oxidizer 802. Heat shield 824 mayinclude openings 832. Openings 832 may provide additional oxidant to aflame in heat shield 824. Openings 832 may stabilize the flame inoxidizer 802 and moderate the temperature of the flame. The size and/ornumber of openings 832 may be varied depending on position of theoxidizer in the oxidizer assembly to moderate the temperature and ensurefuel combustion. Spacers 834 may be positioned on heat shield 824 tokeep oxidizer positioned in the oxidizer conduit.

In some embodiments, the igniters for the oxidizers include temperaturelimited heater elements. When the oxidizer is operating, the temperatureof the oxidizer heats the igniter element above the Curie temperature ofthe igniter element so that skin effect heating goes away andelectricity flows through all or substantially all of the heaterelement. If the igniter element temperature is below the Curietemperature of the igniter element, the electricity flowing through theigniter element is confined to a certain depth so the effectiveresistance of the igniter element increases. The increase in effectiveresistance causes resistive heating that raises the temperature of theigniter element above the ignition temperature of the fuel and gasmixture for the oxidizer.

In some embodiments, catalytic igniters may be used. The catalyticigniters may have long operation life at high temperatures. Catalyticigniters may enable hot restarts without having to shut down all flamesin the remaining burners when one or more burners flame out. The amountof hydrogen can be varied in the fuel supply to the catalytic ignitersso that fluid flow through the oxidizer system does not have to belowered to hit ignition conditions for a particular oxidizer. Undercertain operating conditions, one or more of the catalytic igniterscould be supplied with fuel so that the igniter is hot to assistcombustion in case an oxidizer becomes weak or troublesome due tomanufacturing or long term degradation of the oxidizer. Use of catalyticigniters may allow for relatively simple startups.

In some embodiments, flame stabilizers may be added to the oxidizers.The flame stabilizers may attach the flame to the heat shield. The highbypass flow around the oxidizer cools the heat shield and protects theinternals of the oxidizer from damage. FIGS. 116-120 depict variousembodiments of heat shields 824 with flame stabilizers 836. Flamestabilizer 836 depicted in FIG. 116 is a ring. Flame stabilizer 836depicted in FIG. 117 is an angled ring. The rings may amount to up toabout 25% annular area blockage. The rings may establish a recirculationzone near heat shield 824 and away from the fuel line passing throughthe center of the heat shield.

FIG. 119 depicts an embodiment of multiple flame stabilizers 836 in heatshield 824. Flame shield 824 may have two or more sets of openings 832along an axial length of the flame shield. Rings may be positionedbehind one or more of the sets of openings 832. In some embodiments,adjacent rings may cause interference. To inhibit interference, 3partial rings (each ring being about ⅙ the circumference) may be evenlyspace about the circumference instead of one complete ring. The next setof 3 partial rings along the axial length of heat shield may bestaggered (for example, the rings may be rotated by 120° relative to thefirst set of 3 rings).

FIG. 118 depicts an embodiment of flame stabilizer 836 in heat shield824. Flame stabilizer 836 is a ring that angles over upstream openings832. Flame stabilizer 836 may divert incoming fluid flow throughopenings 832 in an upstream direction. The diverted incoming fluid mayset up a flow condition somewhat analogous to high swirl recirculation(reverse flow). One or more stagnation zones may develop where a flamefront is stable.

FIG. 120 depicts an embodiment wherein flame stabilizers 836 are roundeddeflectors positioned upstream of openings 832. The portion of flamestabilizers 836 positioned over the openings may be cylindrical sectionswith the concave portions facing openings 832. Flame stabilizers 836 maydivert incoming fluid flow and allow the flame root area to developaround the deflectors.

One of more of the oxidizers in an oxidizer assembly may be a catalyticburner. The catalytic burners may include a catalytic portion followedby a homogenous portion. Catalytic burners may be started late in anignition sequence, and may ignite without igniters. Oxidant for thecatalytic burners would be sufficiently hot from upstream burners (forexample, the oxidant may be at a temperature of about 370° C. if thefuel is primarily methane) so that a primary mixture would react overthe catalyst in the catalyst portion and produce enough heat so thatexiting products ignite a secondary mixture in the homogenous portion ofthe oxidizer. In some embodiments, the fuel may include enough hydrogento allow the needed temperature of the oxidant to be lower. Thecatalytic portion of the catalytic burner may use significantly lessfuel than the homogenous portion so that a significant portion of theheat of the catalytic burner is produced in the homogenous portion ofthe burner.

FIG. 121 depicts a cross-sectional representation of catalytic burner838. Oxidant may enter mix chamber 818 through openings 828. Fuel mayenter mix chamber 818 from fuel conduit 806 through fuel openings 826′.Fuel and oxidizer may flow to catalyst 840. Catalyst 840 may includepalladium on a honeycomb ceramic support. The fuel and oxidant react oncatalyst 840 to form hot reaction products. The hot reaction productsmay be directed to heat shield 824. Additional fuel enters heat shield824 through openings 826″ in fuel conduit 806. Additional oxidant entersheat shield 824 through openings 832. The hot reaction productsgenerated by catalyst 840 may ignite fuel and oxidant in autoignitionzone 842. Autoignition zone 842 may allow fuel and oxidant to form maincombustion zone 844.

In some embodiments a catalytic burner may include an igniter tosimplify startup procedures. FIG. 122 depicts catalytic burner 838 thatincludes igniter 816. Igniter 816 is positioned in mix chamber 818.Oxidant enters mix chamber through openings 828A. Fuel enters the mixchamber from fuel line through fuel openings 826A. The fuel input intomixture chamber 818 may be only a small fraction of the fuel input forcatalytic burner 838. Inputs into mixture chamber 818 may be criticalflow orifices to maintain tight control of the mixture under a widerange of operating conditions. Igniter 816 raises the temperature of thefuel and oxidant to combustion temperatures in pre-heat zone 846. Flamestabilizer 836 may be positioned in mixing chamber 818. Heat frompre-heat zone 846 and/or combustion products may heat additional fuelthat enters mixing chamber 818 through fuel openings 826B and additionaloxidant that enters the mixing chamber through openings 828B. Openings826B and openings 828B may be upstream of flame stabilizer 836. Theadditional fuel and oxidant are heated to a temperature sufficient tosupport reaction on catalyst 840.

Heated fuel and oxidant from mixing chamber 818 pass to catalyst 840.The fuel and oxidant react on catalyst 840 to form hot reactionproducts. The hot reaction products may be directed to heat shield 824.Additional fuel enters heat shield 824 through openings 826C in fuelconduit 806. Additional oxidant enters heat shield 824 through openings832. The hot reaction products generated by catalyst 840 may ignite fueland oxidant in autoignition zone 842. Autoignition zone 842 may allowfuel and oxidant to form main combustion zone 844.

In some embodiments, all of the oxidizers in the oxidizer assembly arecatalytic burners. In some embodiments, the first or the first severaloxidizers in the oxidizer assembly are catalytic burners. The oxidantsupplied to these burners may be at a lower temperature than subsequentburners. Using catalytic burners with igniters may stabilize theperformance of the first several oxidizers in the oxidizer assembly.Catalytic burners may be used in-line with other burners to reduceemissions by allowing lower flame temperatures while still havingsubstantially complete combustion.

In some embodiments, a catalytic converter may be positioned at the endof the oxidizer assembly or in the exhaust gas return. The catalyticconverter may remove unburned hydrocarbons and/or remaining oxides ofnitrogen or other pollutants. The catalytic converter may benefit fromthe relatively high temperature of the exhaust gas. In some embodiments,catalytic burners in series may be integrated with coupled catalyticconverters to limit undesired emissions from the oxidizer assembly. Insome embodiments, a selectively permeable material may be used to allowcarbon dioxide or other fluids to be separated from the exhaust gas. Thecarbon dioxide may be sequestered in a spent portion of the formation tosequester the carbon dioxide.

In some embodiments, a flameless distributed combustor may be the frontand/or back burner. Having a flameless distributed combustor as thefront burner may stabilize the front burner and provide heated oxidantto the next oxidizer. Having a flameless distributed combustor as theback burner may ensure that the exhaust is depleted in case one or moreof the oxidizers flame out.

In some embodiments, the igniters may be removable or retractable fromthe flame after ignition. The igniter may be placed in a sheath orpulled back from the flame. Having the ability to remove or retract theigniters may extend the life of the igniters and provide for a morereliable system should one or more of the oxidizers need to berestarted.

The spacing of the oxidizers in an oxidizer assembly may be varied. Thespacing may be varied to accommodate rich and lean portions of theformation. In some embodiments, the heat duty of selected oxidizers maybe increased by using ceramic parts inside the oxidizers. Increasing theheat duty may simplify the overall design and/or permit a system withfewer burners.

In some embodiments, the fuel line may be located adjacent to theoxidizers. A separate line would need to be routed from the fuel line toeach oxidizer. Air shields would be needed to shield and stabilize theflame due to the high gas flow requirements. Also, shielding may beneeded to protect oxidizer components.

In some in situ heat treatment embodiments, a downhole gas turbine isused to provide a portion of the electricity for an electric heater. Theexhaust from the gas turbine may heat the formation. The heater may be atemperature limited heater in a horizontal section of a U-shaped well.In some embodiments, the substantially horizontal section of theU-shaped well is over 1000 m long, over 1300 m long, over 1600 m long,or over 1900 m long.

FIG. 123 depicts a schematic representation of a heating system with adownhole gas turbine. Gas turbine 848 is placed at or near thetransition between overburden 458 and hydrocarbon layer 460. Gas turbine848 may include electrical generator 850 and turbine gas combustor 852.Inlet leg 854 to gas turbine 848 may have a relatively large diameter.The diameter may be 0.3 m, 0.4 m, 0.5 m or greater. Oxidant line 856 andfuel line 858 supply gas turbine 848. In some embodiments, fuel line 858is placed within oxidant line 856, or the oxidant line is placed in thefuel line. In some embodiments, the oxidant line is positioned adjacentto the fuel line. In some embodiments, inlet oxidant and fuel are usedto cool gas turbine 848. Oxidant may be, but is not limited to, air,oxygen, or oxygen enriched air.

Electricity provided by electrical generator 850 is directed totemperature limited heater 860 through lead-in conductors 862. Lead-inconductors 862 may be insulated conductors. If electrical generator 850is not able to supply enough electricity to temperature limited heater860 to heat hydrocarbon layer 460 to a desired temperature, additionalelectricity may be supplied to the temperature limited heater through aconductor placed in inlet leg 850 and electrically coupled to thetemperature limited heater.

Exhaust gas from gas turbine 852 passes through tubular 864 to outlet866. In an embodiment, the tubular is 4″ stainless steel pipe placed ina 6″ wellbore. The exhaust gases heat an initial section of hydrocarbonlayer 460 before the gases become too cool to heat the hydrocarbon layerto the desired temperature. Temperature limited heater 860 begins aselected distance from gas turbine 848. The distance may be 200 m, 150m, 100 m, or less. Heat provided to the portion of the formation fromgas turbine 848 to temperature limited heater 860 may come from theexhaust gases passing through tubular 864. Temperature limited heater860, which is at least partially supplied with electricity generated bygas turbine 848, heats hydrocarbon layer 460 and the exhaust gases fromthe gas turbine. Temperature limited heater 860 may be an insulatedconductor heater with a self-limiting temperature of about 760° C. Insome embodiments, temperature limited heater 860 is placed in tubular864. In other embodiments, the temperature limited heater is on theoutside of the tubular. Temperature limited heater 860 may end at aselected horizontal distance from the outlet 866 of the temperaturelimited heater. The distance may be 200 m, 150 m, 100 m, or less. Theexhaust gases heated by temperature limited heater 860 transfer heat tohydrocarbon layer 460 before passing through overburden 458 to outlet866.

Inlets and outlets of the U-shaped wells for heating a portion of theformation may be placed in alternating directions in adjacent wells.Alternating inlets and outlets of the U-shaped wells may allow foruniform heating of the hydrocarbon layer of the formation.

In some embodiments, a portion of oxidant for gas turbine 848 is routedto the gas turbine from outlet 866 of an adjacent U-shaped well. Theportion of oxidant may be sent to the gas turbine through a separateline. Using oxidant from the exit of the adjacent well may allow some ofthe oxidant and/or heat from the exiting exhaust gases to be recoveredand utilized. The separate exhaust gas line to the gas turbine maytransfer heat to the main oxidant line and/or fuel line to the gasturbine.

Compressors and partial expanders may be located at the surface.Compressed fuel lines and oxidant lines extend to gas turbine 848.Generators, burners, and expanders of the gas turbine may be located ator near the transition between the overburden and the hydrocarbon layerthat is to be heated. Locating equipment in this manner may reduce thecomplexity of the downhole equipment, and reduce pressure drops for theoxidant going down the wellbore and the combustion gases going throughthe heater sections and back to the surface. The surface expander for afirst well can expand gases from an adjacent well outlet since theadjacent well outlet is physically closer to the inlet of the first wellthan is the outlet of the first well. Moving compressed fuel andcompressed oxidant down to the gas turbine may result in less pressuredrop as compared to having cool fuel and oxidant travel down to the gasturbine. Placing gas turbine 848 at or near the transition betweenoverburden 458 and hydrocarbon layer 460 allows exhaust gas from the gasturbine to heat portions of the formation that are to be pyrolyzed.Placing the gas turbine 848 at or near the transition between overburden458 and hydrocarbon layer 460 may eliminate or reduce the amount ofinsulation needed between the overburden and inlet leg 854. In someembodiments, tapered insulation may be applied at the exit of gasturbine 848 to reduce excess heating of the formation near the gasturbine.

In some in situ heat treatment process embodiments, a circulation systemis used to heat the formation. The circulation system may be a closedloop circulation system. FIG. 124 depicts a schematic representation ofa system for heating a formation using a circulation system. The systemmay be used to heat hydrocarbons that are relatively deep in the groundand that are in formations that are relatively large in extent. In someembodiments, the hydrocarbons may be 100 m, 200 m, 300 m or more belowthe surface. The circulation system may also be used to heathydrocarbons that are not as deep in the ground. The hydrocarbons may bein formations that extend lengthwise up to 500 m, 750 m, 1000 m, ormore. The circulation system may become economically viable informations where the length of the hydrocarbon containing formation tobe treated is long compared to the thickness of the overburden. Theratio of the hydrocarbon formation extent to be heated by heaters to theoverburden thickness may be at least 3, at least 5, or at least 10. Theheaters of the circulation system may be positioned relative to adjacentheaters so that superposition of heat between heaters of the circulationsystem allows the temperature of the formation to be raised at leastabove the boiling point of aqueous formation fluid in the formation.

In some embodiments, heaters 760 may be formed in the formation bydrilling a first wellbore and then drilling a second wellbore thatconnects with the first wellbore. Piping may be positioned in theU-shaped wellbore to form U-shaped heater 760. Heaters 760 are connectedto heat transfer fluid circulation system 868 by piping. Gas at highpressure may be used as the heat transfer fluid in the closed loopcirculation system. In some embodiments, the heat transfer fluid iscarbon dioxide. Carbon dioxide is chemically stable at the requiredtemperatures and pressures and has a relatively high molecular weightthat results in a high volumetric heat capacity. Other fluids such assteam, air, helium and/or nitrogen may also be used. The pressure of theheat transfer fluid entering the formation may be 3000 kPa or higher.The use of high pressure heat transfer fluid allows the heat transferfluid to have a greater density, and therefore a greater capacity totransfer heat. Also, the pressure drop across the heaters is less for asystem where the heat transfer fluid enters the heaters at a firstpressure for a given mass flow rate than when the heat transfer fluidenters the heaters at a second pressure at the same mass flow rate whenthe first pressure is greater than the second pressure. In someembodiments, a liquid heat transfer fluid may be used. The liquid heattransfer fluid may be a natural or synthetic oil, or other type of hightemperature heat transfer fluid.

Heat transfer fluid circulation system 868 may include heat supply 870,first heat exchanger 872, second heat exchanger 874, and compressor 876.Heat supply 870 heats the heat transfer fluid to a high temperature.Heat supply 870 may be a furnace, solar collector, chemical reactor,nuclear reactor, fuel cell exhaust heat, or other high temperaturesource able to supply heat to the heat transfer fluid. In the embodimentdepicted in FIG. 124, heat supply 870 is a furnace that heats the heattransfer fluid to a temperature in a range from about 700° C. to about920° C., from about 770° C. to about 870° C., or from about 800° C. toabout 850° C. In an embodiment, heat supply 870 heats the heat transferfluid to a temperature of about 820° C. The heat transfer fluid flowsfrom heat supply 870 to heaters 760. Heat transfers from heaters 760 toformation 758 adjacent to the heaters. The temperature of the heattransfer fluid exiting formation 758 may be in a range from about 350°C. to about 580° C., from about 400° C. to about 530° C., or from about450° C. to about 500° C. In an embodiment, the temperature of the heattransfer fluid exiting formation 758 is about 480° C. The metallurgy ofthe piping used to form heat transfer fluid circulation system 868 maybe varied to significantly reduce costs of the piping. High temperaturesteel may be used from heat supply 870 to a point where the temperatureis sufficiently low so that less expensive steel can be used from thatpoint to first heat exchanger 872. Several different steel grades may beused to form the piping of heat transfer fluid circulation system 868.

Heat transfer fluid from heat supply 870 of heat transfer fluidcirculation system 868 passes through overburden 458 of formation 758 tohydrocarbon layer 460. Portions of heaters 760 extending throughoverburden 458 may be insulated. In some embodiments, the insulation orpart of the insulation is a polyimide insulating material. Inletportions of heaters 760 in hydrocarbon layer 460 may have taperinginsulation to reduce overheating of the hydrocarbon layer near the inletof the heater into the hydrocarbon layer.

In some embodiments, the diameter of the pipe in overburden 458 may besmaller than the diameter of pipe through hydrocarbon layer 460. Thesmaller diameter pipe through overburden 458 may allow for less heattransfer to the overburden. Reducing the amount of heat transfer tooverburden 458 reduces the amount of cooling of the heat transfer fluidsupplied to pipe adjacent to hydrocarbon layer 460. The increased heattransfer in the smaller diameter pipe due to increased velocity of heattransfer fluid through the small diameter pipe is offset by the smallersurface area of the smaller diameter pipe and the decrease in residencetime of the heat transfer fluid in the smaller diameter pipe.

After exiting formation 758, the heat transfer fluid passes throughfirst heat exchanger 872 and second heat exchanger 874 to compressor876. First heat exchanger 872 transfers heat between heat transfer fluidexiting formation 758 and heat transfer fluid exiting compressor 876 toraise the temperature of the heat transfer fluid that enters heat supply870 and reduce the temperature of the fluid exiting formation 758.Second heat exchanger 874 further reduces the temperature of the heattransfer fluid before the heat transfer fluid enters compressor 876.

FIG. 125 depicts a plan view of an embodiment of wellbore openings inthe formation that is to be heated using the circulation system. Heattransfer fluid entries 878 into formation 758 alternate with heattransfer fluid exits 880. Alternating heat transfer fluid entries 878with heat transfer fluid exits 880 may allow for more uniform heating ofthe hydrocarbons in formation 758.

In some embodiments, piping for the circulation system may allow thedirection of heat transfer fluid flow through the formation to bechanged. Changing the direction of heat transfer fluid flow through theformation allows each end of a unshaped wellbore to initially receivethe heat transfer fluid at the heat transfer fluid's hottest temperaturefor a period of time, which may result in more uniform heating of theformation. The direction of heat transfer fluid may be changed atdesired time intervals. The desired time interval may be about a year,about six months, about three months, about two months or any otherdesired time interval.

In some embodiments, nuclear energy may be used to heat the heattransfer fluid used in the circulation system to heat a portion of theformation. Heat supply 870 in FIG. 124 may be a pebble bed reactor orother type of nuclear reactor, such as a light water reactor. The use ofnuclear energy provides a heat source with no carbon dioxide emissions.Also, the use of nuclear energy can be more efficient because energylosses resulting from the conversion of heat to electricity andelectricity to heat are avoided by directly utilizing the heat producedfrom the nuclear reactions without producing electricity.

In some embodiments, a nuclear reactor may heat helium. For example,helium flows through a pebble bed reactor, and heat transfers to thehelium. The helium may be used as the heat transfer fluid to heat theformation. In some embodiments, the nuclear reactor may heat helium, andthe helium may be passed through a heat exchanger to provide heat to theheat transfer fluid used to heat the formation. The pebble bed reactormay include a pressure vessel that contains encapsulated enricheduranium dioxide fuel. Helium may be used as a heat transfer fluid toremove heat from the pebble bed reactor. Heat may be transferred in aheat exchanger from the helium to the heat transfer fluid used in thecirculation system. The heat transfer fluid used in the circulationsystem may be carbon dioxide, a molten salt, or other fluid. Pebble bedreactor systems are available from PBMR Ltd (Centurion, South Africa).

FIG. 126 depicts a schematic diagram of a system that uses nuclearenergy to heat treatment area 882. The system may include helium systemgas blower 884, nuclear reactor 886, heat exchanger units 888, and heattransfer fluid blower 890. Helium system gas blower 884 may draw heatedhelium from nuclear reactor 886 to heat exchanger units 888. Helium fromheat exchanger units 888 may pass through helium system gas blower 884to nuclear reactor 886. Helium from nuclear reactor 886 may be at atemperature of about 900° C. to about 1000° C. Helium from helium gasblower 884 may be at a temperature of about 500° C. to about 600° C.Heat transfer fluid blower 890 may draw heat transfer fluid from heatexchanger units 888 through treatment area 882. Heat transfer fluid maypass through heat transfer fluid blower 890 to heat exchanger units 888.The heat transfer fluid may be carbon dioxide. The heat transfer fluidmay be at a temperature from about 850° C. to about 950° C. afterexiting heat exchanger units 888.

In some embodiments, the system may include auxiliary power unit 900. Insome embodiments, auxiliary power unit 900 generates power by passingthe helium from heat exchanger units 888 through a generator to makeelectricity. The helium may be sent to one or more compressors and/orheat exchangers to adjust the pressure and temperature of the heliumbefore the helium is sent to nuclear reactor 886. In some embodiments,auxiliary power unit 900 generates power using a heat transfer fluid(for example, ammonia or aqua ammonia). Helium from heat exchanger units888 is sent to additional heat exchanger units to transfer heat to theheat transfer fluid. The heat transfer fluid is taken through a powercycle (such as a Kalina cycle) to generate electricity. In anembodiment, nuclear reactor 886 is a 400 MW reactor and auxiliary powerunit 900 generates about 30 MW of electricity.

FIG. 127 depicts a schematic elevational view of an arrangement for anin situ heat treatment process. U-shaped wellbores may be formed in theformation to define treatment areas 882A, 882B, 882C, 882D. Additionaltreatment areas could be formed to the sides of the shown treatmentareas. Treatment areas 882A, 882B, 882C, 882D may have widths of over300 m, 500 m, 1000 m, or 1500 m. Well exits and entrances for thewellbores may be formed in well openings area 902. Rail lines 904 may beformed along sides of treatment areas 882. Warehouses, administrationoffices and/or spent fuel storage facilities may be located near ends ofrail lines 904. Facilities 906 may be formed at intervals along spurs ofrail lines 904. Each facility 906 may include a nuclear reactor,compressors, heat exchanger units and other equipment needed forcirculating hot heat transfer fluid to the wellbores. Facilities 906 mayalso include surface facilities for treating formation fluid producedfrom the formation. In some embodiments, heat transfer fluid produced infacility 906′ may be reheated by the reactor in facility 906″ afterpassing through treatment area 882A. In some embodiments, each facility906 is used to provide hot treatment fluid to wells in one half of thetreatment area 882 adjacent to the facility. Facilities 906 may be movedby rail to another facility site after production from a treatment areais completed.

Circulation systems may be used to heat portions of the formation.Production wells in the formation are used to remove produced fluids.After production from the formation has ended, the circulation systemmay be used to recover heat from the formation. FIG. 124 depicts anembodiment of a circulation system. Heat transfer fluid may becirculated through heaters 760 after heat supply 870 is disconnectedfrom the circulation system. The heat transfer fluid may be a differentheat transfer fluid than the heat transfer fluid used to heat theformation. Heat transfers from the heated formation to the heat transferfluid. The heat transfer fluid may be used to heat another portion ofthe formation or the heat transfer fluid may be used for other purposes.In some embodiments, water is introduced into heaters 760 to producesteam. In some embodiments, low temperature steam is introduced intoheaters 760 so that the passage of the steam through the heatersincreases the temperature of the steam. Other heat transfer fluidsincluding natural or synthetic oils, such as Syltherm oil (Dow CorningCorporation (Midland, Mich., U.S.A.), may be used instead of steam orwater.

In some embodiments, the circulation system may be used in conjunctionwith electrical heating. In some embodiments, at least a portion of thepipe in the U-shaped wellbores adjacent to portions of the formationthat are to be heated is made of a ferromagnetic material. For example,the piping adjacent to a layer or layers of the formation to be heatedis made of a 9% to 13% chromium steel, such as 410 stainless steel. Thepipe may be a temperature limited heater when time varying electriccurrent is applied to the piping. The time varying electric current mayresistively heat the piping, which heats the formation. In someembodiments, direct electric current may be used to resistively heat thepiping, which heats the formation.

In some embodiments, the circulation system is used to heat theformation to a first temperature, and electrical energy is used tomaintain the temperature of the formation and/or heat the formation tohigher temperatures. The first temperature may be sufficient to vaporizeaqueous formation fluid in the formation. The first temperature may beat most about 200° C., at most about 300° C., at most about 350° C., orat most about 400° C. Using the circulation system to heat the formationto the first temperature allows the formation to be dry when electricityis used to heat the formation. Heating the dry formation may minimizeelectrical current leakage into the formation.

In some embodiments, the circulation system and electrical heating maybe used to heat the formation to a first temperature. The formation maybe maintained, or the temperature of the formation may be increased fromthe first temperature, using the circulation system and/or electricalheating. In some embodiments, the formation may be raised to the firsttemperature using electrical heating, and the temperature may bemaintained and/or increased using the circulation system. Economicfactors, available electricity, availability of fuel for heating theheat transfer fluid, and other factors may be used to determine whenelectrical heating and/or circulation system heating are to be used.

In certain embodiments, the portion of heater 760 in hydrocarbon layer460 is coupled to lead-in conductors. Lead-in conductors may be locatedin overburden 458. Lead-in conductors may electrically couple theportion of heater 760 in hydrocarbon layer 460 to one or more wellheadsat the surface. Electrical isolators may be located at a junction of theportion of heater 760 in hydrocarbon layer 460 with portions of heater760 in overburden 458 so that the portions of the heater in theoverburden are electrically isolated from the portion of the heater inthe hydrocarbon layer. In some embodiments, the lead-in conductors areplaced inside of the pipe of the closed loop circulation system. In someembodiments, the lead-in conductors are positioned outside of the pipeof the closed loop circulation system. In some embodiments, the lead-inconductors are insulated conductors with mineral insulation, such asmagnesium oxide. The lead-in conductors may include highly electricallyconductive materials such as copper or aluminum to reduce heat losses inoverburden 458 during electrical heating.

In certain embodiments, the portions of heater 760 in overburden 458 maybe used as lead-in conductors. The portions of heater 760 in overburden458 may be electrically coupled to the portion of heater 760 inhydrocarbon layer 460. In some embodiments, one or more electricallyconducting materials (such as copper or aluminum) are coupled (forexample, cladded or welded) to the portions of heater 760 in overburden458 to reduce the electrical resistance of the portions of the heater inthe overburden. Reducing the electrical resistance of the portions ofheater 760 in overburden 458 reduces heat losses in the overburdenduring electrical heating.

In some embodiments, the portion of heater 760 in hydrocarbon layer 460is a temperature limited heater with a self-limiting temperature betweenabout 600° C. and about 1000° C. The portion of heater 760 inhydrocarbon layer 460 may be a 9% to 13% chromium stainless steel. Forexample, portion of heater 760 in hydrocarbon layer 460 may be 410stainless steel. Time-varying current may be applied to the portion ofheater 760 in hydrocarbon layer 460 so that the heater operates as atemperature limited heater.

FIG. 128 depicts a side view representation of an embodiment of a systemfor heating a portion of a formation using a circulated fluid systemand/or electrical heating. Wellheads 450 of heaters 760 may be coupledto heat transfer fluid circulation system 868 by piping. Wellheads 450may also be coupled to electrical power supply system 908. In someembodiments, heat transfer fluid circulation system 868 is disconnectedfrom the heaters when electrical power is used to heat the formation. Insome embodiments, electrical power supply system 908 is disconnectedfrom the heaters when heat transfer fluid circulation system 868 is usedto heat the formation.

Electrical power supply system 908 may include transformer 728 andcables 722, 724. In certain embodiments, cables 722, 724 are capable ofcarrying high currents with low losses. For example, cables 722, 724 maybe thick copper or aluminum conductors. The cables may also have thickinsulation layers. In some embodiments, cable 722 and/or cable 724 maybe superconducting cables. The superconducting cables may be cooled byliquid nitrogen. Superconducting cables are available from Superpower,Inc. (Schenectady, N.Y., U.S.A.). Superconducting cables may minimizepower loss and/or reduce the size of the cables needed to coupletransformer 728 to the heaters. In some embodiments, cables 722, 724 maybe made of carbon nanotubes.

In some embodiments, geothermal energy may be used to heat or preheat atreatment area of an in situ heat treatment process or a treatment areato be solution mined. Geothermal energy may have little or no carbondioxide emissions. In some embodiments, hot fluid may be produced from alayer or layers located below or near the treatment area. The hot fluidmay be steam, water, and/or brine. One or more of the layers may begeothermally pressurized geysers. Hot fluid may be pumped from one ormore of the layers. The layer or layers may be 2 km, 4 km, 8 km or morebelow the surface. The hot fluid may be at a temperature of over 100°C., over 200° C., or over 300° C.

The hot fluid may be produced and circulated through piping in thetreatment area to raise the temperature of the treatment area. In someembodiments, the hot fluid is introduced directly into the treatmentarea. In some embodiments, the hot fluid is circulated through thetreatment area or piping in the treatment area without being produced tothe surface and re-introduced into the treatment area. In someembodiments, the hot fluid may be produced from a location near thetreatment area. The hot fluid may be transported to the treatment area.Once transported to the treatment area, the hot fluid is circulatedthrough piping in the treatment area or the hot fluid is introduceddirectly into the treatment area.

In some embodiments, hot fluid produced from a layer or layers is usedto solution mine minerals from the formation. The hot fluid may be usedto raise the temperature of the formation to a temperature below thedissociation temperature of the minerals but to a temperature highenough to increase the amount of mineral going into solution in a firstfluid introduced into the formation. The hot fluid may be introduceddirectly into the formation as all or a portion of the first fluid, orthe hot fluid may be circulated through piping in the formation.

In some embodiments, hot fluid produced from a layer or layers may beused to heat the treatment area before using electrical energy or othertypes of heat sources to heat the treatment area to pyrolysistemperatures. The hot fluid may not be at a temperature sufficient toraise the temperature of the treatment area to pyrolysis temperatures.Using the hot fluid to heat the treatment area before using electricalheaters or other heat sources to heat the treatment area to pyrolysistemperatures may reduce energy costs for the in situ heat treatmentprocess.

In some embodiments, hot dry rock technology may be used to producesteam or other hot heat transfer fluid from a deep portion of theformation. Injection wells may be drilled to a depth where the formationis hot. The injection wells may be over 2 km, over 4 km, or over 8 kmdeep. Sections of the formation adjacent to the bottom portions of theinjection wells may be hydraulically or otherwise fractured to providelarge contact area with the formation and/or to provide flow paths toheated fluid production wells. Water, steam and/or other heat transferfluid may be introduced into the formation through the injection wells.Heat transfers to the introduced fluid from the formation. Steam and/orhot heat transfer fluid may be produced from the heated fluid productionwells. In some embodiments, the steam and/or hot heat transfer fluid isdirected into the treatment area from the production wells without firstproducing the steam and/or hot heat transfer fluid to the surface. Thesteam and/or hot heat transfer fluid may be used to heat a portion of ahydrocarbon containing formation above the deep hot portion of theformation.

In some embodiments, steam produced from heated fluid production wellsmay be used as the steam for a drive process (for example, a steam floodprocess or steam assisted gravity drainage process). In someembodiments, steam or other hot heat transfer fluid produced throughheated fluid production wells is passed through U-shaped wellbores orother types of wellbores to provide initial heating to the formation. Insome embodiments, cooled steam or water, or cooled heat transfer fluid,resulting from the use of the steam and/or heat transfer fluid from thehot portion of the formation may be collected and sent to the hotportion of the formation to be reheated.

In certain embodiments, a controlled or staged in situ heating andproduction process is used to in situ heat treat a hydrocarboncontaining formation (for example, an oil shale formation). The stagedin situ heating and production process may use less energy input toproduce hydrocarbons from the formation than a continuous or batch insitu heat treatment process. In some embodiments, the staged in situheating and production process is about 30% more efficient in treatingthe formation than the continuous or batch in situ heat treatmentprocess. The staged in situ heating and production process may alsoproduce less carbon dioxide emissions than a continuous or batch in situheat treatment process. In certain embodiments, the staged in situheating and production process is used to treat rich layers in the oilshale formation. Treating only the rich layers may be more economicalthan treating both rich layers and lean layers because heat may bewasted heating the lean layers.

FIG. 129 depicts a top view representation of an embodiment for thestaged in situ heating and producing process for treating the formation.In certain embodiments, heaters 716 are arranged in triangular patterns.In other embodiments, heaters 716 are arranged in any other regular orirregular patterns. The heater patterns may be divided into one or moresections 910, 912, 914, 916, and/or 918. The number of heaters 716 ineach section may vary depending on, for example, properties of theformation or a desired heating rate for the formation. One or moreproduction wells 206 may be located in each section 910, 912, 914, 916,and/or 918. In certain embodiments, production wells 206 are located ator near the centers of the sections. In some embodiments, productionwells 206 are in other portions of sections 910, 912, 914, 916, and 918.Production wells 206 may be located at other locations in sections 910,912, 914, 916, and/or 918 depending on, for example, a desired qualityof products produced from the sections and/or a desired production ratefrom the formation.

In certain embodiments, heaters 716 in one of the sections are turned onwhile the heaters in other sections remain turned off. For example,heaters 716 in section 910 may be turned on while the heaters in theother sections are left turned off. Heat from heaters 716 in section 910may create permeability, mobilize fluids, and/or pyrolysis fluids insection 910. While heat is being provided by heaters 716 in section 910,production well 206 in section 912 may be opened to produce fluids fromthe formation. Some heat from heaters 716 in section 910 may transfer tosection 912 and “pre-heat” section 912. The pre-heating of section 912may create permeability in section 912, mobilize fluids in section 912,and allow fluids to be produced from the section through production well206. As fluids are produced from section 912, the movement of fluidsfrom section 910 to section 912 transfers heat between the sections. Themovement of the hot fluids through the formation increases heat transferwithin the formation. Allowing hot fluids to flow between the sectionsuses the energy of the hot fluids for heating of unheated sectionsrather than removing the heat from the formation by producing the hotfluids directly from section 910. Thus, the movement of the hot fluidsallows for less energy input to get production from the formation thanis required if heat is provided from heaters 716 in both sections to getproduction from the sections.

In some embodiments, section 910 and/or section 912 may be treated priorto turning on heaters 716 to increase the permeability in the sections.For example, the sections may be dewatered to increase the permeabilityin the sections. In some embodiments, steam injection or other fluidinjection may be used to increase the permeability in the sections.

In certain embodiments, after a selected time, heaters 716 in section912 are turned on. Turning on heaters 716 in section 912 may provideadditional heat to sections 910 and 912 to increase the permeability,mobility, and/or pyrolysis of fluids in these sections. In someembodiments, as heaters 716 in section 912 are turned on, production insection 912 is turned off (shut down) and production well 206 in section914 is opened to produce fluids from the formation. Thus, fluid flow inthe formation towards production well 206 in section 914 and section 914is heated by the flow of hot fluids as described above for section 912.In some embodiments, production well 206 in section 912 may be left openafter the heaters are turned on in the section, if desired. This processmay be repeated for subsequent sections in the formation. For example,after a selected time, heaters in section 914 may be turned on andfluids produced from production well 206 in section 916 and so onthrough the formation.

In some embodiments, heat is provided by heaters 716 in alternatingsections (for example, sections 910, 914, and 918) while fluids areproduced from the sections in between the heated sections (for example,sections 912 and 916). After a selected time, heaters 716 in theunheated sections (sections 912 and 916) are turned on and fluids areproduced from one or more of the sections as desired.

In certain embodiments, a smaller heater spacing is used in the stagedin situ heating and producing process than in the continuous or batch insitu heat treatment processes. For example, the continuous or batch insitu heat treatment process may use a heater spacing of about 12 m whilethe in situ staged heating and producing process uses a heater spacingof about 10 m. The staged in situ heating and producing process may usethe smaller heater spacing because the staged process allows forrelatively rapid heating of the formation and expansion of theformation.

In some embodiments, the sequence of heated sections begins with theoutermost sections and moves inwards. For example, for a selected time,heat may be provided by heaters 716 in sections 910 and 918 as fluidsare produced from sections 912 and 916. After the selected time, heaters716 in sections 912 and 916 may be turned on and fluids are producedfrom section 914. After another selected amount of time, heaters 716 insection 914 may be turned on, if needed.

In certain embodiments, sections 910-918 are substantially equal sizedsections. The size and/or location of sections 910-918 may vary based ondesired heating and/or production from the formation. For example,simulation of the staged in situ heating and production processtreatment of the formation may be used to determine the number ofheaters in each section, the optimum pattern of sections and/or thesequence for heater power up and production well startup for the stagedin situ heating and production process. The simulation may account forproperties such as, but not limited to, formation properties and desiredproperties and/or quality in the produced fluids. In some embodiments,heaters 716 at the edges of the treated portions of the formation (forexample, heaters 716 at the left edge of section 910 or the right edgeof section 918) may have tailored or adjusted heat outputs to producedesired heat treatment of the formation.

In some embodiments, the formation is sectioned into a checkerboardpattern for the staged in situ heating and production process. FIG. 130depicts a top view of rectangular checkerboard pattern 920 embodimentfor the staged in situ heating and production process. In someembodiments, heaters in the “A” sections (sections 910A, 912A, 914A,916A, and 918A) may be turned on and fluids are produced from the “B”sections (sections 910B, 912B, 914B, 916B, and 918B). After the selectedtime, heaters in the “B” sections may be turned on. The size and/ornumber of “A” and “B” sections in rectangular checkerboard pattern 920may be varied depending on factors such as, but not limited to, heaterspacing, desired heating rate of the formation, desired production rate,size of treatment area, subsurface geomechanical properties, subsurfacecomposition, and/or other formation properties.

In some embodiments, heaters in sections 910A are turned on and fluidsare produced from sections 910B and/or sections 912B. After the selectedtime, heaters in sections 912A may be turned on and fluids are producedfrom sections 912B and/or 914B. After another selected time, heaters insections 914A may be turned on and fluids are produced from sections914B and/or 916B. After another selected time, heaters in sections 916Amay be turned on and fluids are produced from sections 916B and/or 918B.In some embodiments, heaters in a “B” section that has been producedfrom may be turned on when heaters in the subsequent “A” section areturned on. For example, heaters in section 910B may be turned on whenthe heaters in section 912A are turned on. Other alternating heaterstartup and production sequences may also be contemplated for the insitu staged heating and production process embodiment depicted in FIG.130.

In some embodiments, the formation is divided into a circular, ring, orspiral pattern for the staged in situ heating and production process.FIG. 131 depicts a top view of the ring pattern embodiment for thestaged in situ heating and production process. Sections 910, 912, 914,916, and 918 may be treated with heater startup and production sequencessimilar to the sequences described above for the embodiments depicted inFIGS. 129. The heater startup and production sequences for theembodiment depicted in FIG. 131 may start with section 910 (goinginwards towards the center) or with section 918 (going outwards from thecenter). Starting with section 910 may allow expansion of the formationas heating moves towards the center of the ring pattern. Shearing of theformation may be minimized or inhibited because the formation is allowedto expand into heated and/or pyrolyzed portions of the formation. Insome embodiments, the center section (section 918) is cooled aftertreatment.

FIG. 132 depicts a top view of a checkerboard ring pattern embodimentfor the staged in situ heating and production process. The embodimentdepicted in FIG. 132 divides the ring pattern embodiment depicted in 131into a checkerboard pattern similar to the checkerboard pattern depictedin FIG. 130. Sections 910A, 912A, 914A, 916A, 918A, 910B, 912B, 914B,916B, and 918B, depicted in 132, may be treated with heater startup andproduction sequences similar to the sequences described above for theembodiment depicted in 130.

In some embodiments, fluids are injected to drive fluids betweensections of the formation. Injecting fluids such as steam or carbondioxide may increase the mobility of hydrocarbons and may increase theefficiency of the staged in situ heating and production process. In someembodiments, fluids are injected into the formation after the in situheat treatment process to recover heat from the formation. In someembodiments, the fluids injected into the formation for heat recoveryinclude some fluids produced from the formation (for example, carbondioxide, water, and/or hydrocarbons produced from the formation). Insome embodiments, the embodiments depicted in FIGS. 129-132 are used forin situ solution mining of the formation. Hot water or another fluid maybe used to get permeability in the formation at low temperatures forsolution mining.

In certain embodiments, several rectangular checkerboard patterns (forexample, rectangular checkerboard pattern 920 depicted in FIG. 130) areused to treat a treatment area of the formation. FIG. 133 depicts a topview of a plurality of rectangular checkerboard patterns 920(1-36) intreatment area 882 for the staged in situ heating and productionprocess. Treatment area 882 may be enclosed by barrier 922. Each ofrectangular checkerboard patterns 920(1-36) may individually be treatedaccording to embodiments described above for the rectangularcheckerboard patterns.

In certain embodiments, the startup of treatment of rectangularcheckerboard patterns 920(1-36) proceeds in a sequential process. Thesequential process may include starting the treatment of each of therectangular checkerboard patterns one by one sequentially. For example,treatment of a second rectangular checkerboard pattern (for example, theonset of heating of the second rectangular checkerboard pattern) may bestarted after treatment of a first rectangular checkerboard pattern andso on. The startup of treatment of the second rectangular checkerboardpattern may be at any point in time after the treatment of the firstrectangular checkerboard pattern has begun. The time selected forstartup of treatment of the second rectangular checkerboard pattern maybe varied depending on factors such as, but not limited to, desiredheating rate of the formation, desired production rate, subsurfacegeomechanical properties, subsurface composition, and/or other formationproperties. In some embodiments, the startup of treatment of the secondrectangular checkerboard pattern begins after a selected amount offluids have been produced from the first rectangular checkerboardpattern area or after the production rate from the first rectangularcheckerboard pattern increases above a selected value or falls below aselected value.

In some embodiments, the startup sequence for rectangular checkerboardpatterns 920(1-36) is arranged to minimize or inhibit expansion stressesin the formation. In an embodiment, the startup sequence of therectangular checkerboard patterns proceeds in an outward spiralsequence, as shown by the arrows in FIG. 133. The outward spiralsequence proceeds sequentially beginning with treatment of rectangularcheckerboard pattern 920-1, followed by treatment of rectangularcheckerboard pattern 920-2, rectangular checkerboard pattern 920-3,rectangular checkerboard pattern 920-4, and continuing the sequence upto rectangular checkerboard pattern 920-36. Sequentially starting therectangular checkerboard patterns in the outwards spiral sequence mayminimize or inhibit expansion stresses in the formation.

Starting treatment in rectangular checkerboard patterns at or near thecenter of treatment area 882 and moving outwards maximizes the startingdistance from barrier 922. Barrier 922 may be most likely to fail whenheat is provided at or near the barrier. Starting treatment/heating ator near the center of treatment area 882 delays heating of rectangularcheckerboard patterns near barrier 922 until later times of heating intreatment area 882 or at or near the end of production from thetreatment area. Thus, if barrier 922 does fail, the failure of thebarrier occurs after a significant portion of treatment area 882 hasbeen treated.

Starting treatment in rectangular checkerboard patterns at or near thecenter of treatment area 882 and moving outwards also creates open porespace in the inner portions of the outward moving startup pattern. Theopen pore space allows portions of the formation being started at latertimes to expand inwards into the open pore space and, for example,minimize shearing in the formation.

In some embodiments, support sections are left between one or more ofrectangular checkerboard patterns 920(1-36). The support sections may beunheated sections that provide support against geomechanical shifting,shearing, and/or expansion stress in the formation. In some embodiments,some heat may be provided in the support sections. The heat provided inthe support sections may be less than heat provided inside rectangularcheckerboard patterns 920(1-36). In some embodiments, each of thesupport sections may include alternating heated and unheated sections.In some embodiments, fluids are produced from one or more of theunheated support sections.

In some embodiments, one or more of rectangular checkerboard patterns920(1-36) have varying sizes. For example, the outer rectangularcheckerboard patterns (such as rectangular checkerboard patterns920(21-26) and rectangular checkerboard patterns 920(31-36)) may havesmaller areas and/or numbers of checkerboards. Reducing the area and/orthe number of checkerboards in the outer rectangular checkerboardpatterns may reduce expansion stresses and/or geomechanical shifting inthe outer portions of treatment area 882. Reducing the expansionstresses and/or geomechanical shifting in the outer portions oftreatment area 882 may minimize or inhibit expansion stress and/orshifting stress on barrier 922.

During an in situ heat treatment process, some formation fluid maymigrate outwards from the treatment area. The formation fluid mayinclude benzene and other contaminants. Some portions of the formationthat contaminants migrate to will be subsequently treated when a newtreatment area is define and processed using the in situ heat treatmentprocess. Such contaminants may be removed or destroyed by the subsequentin situ heat treatment process. Some areas of the formation to whichcontaminants migrate may not become part of a new treatment areasubjected to in situ heat treatment. Migration inhibition systems may beimplemented to inhibit contaminants from migrating to areas in theformation that are not to be subjected to in situ heat treatment.

In some embodiments, a barrier (for example, a low temperature zone orfreeze barrier) surrounds at least a portion of the perimeter of atreatment area. The barrier may be 20 m to 100 m from the closestheaters in the treatment area used in the in situ heat treatment processto heat the formation. Some contaminants may migrate outwards toward thebarrier through fractures or highly permeable zones and condense in theformation.

In some in situ heat treatment embodiments, a migration inhibitionsystem may be used to minimize or eliminate migration of formation fluidfrom the treatment area of the in situ heat treatment process. FIG. 134depicts a representation of a fluid migration inhibition system. Barrier922 may surround treatment area 882. Migration inhibition wells 924 maybe placed in the formation between barrier 922 and treatment area 882.Migration inhibition wells 924 may be offset from wells used to heat theformation and/or from production wells used to produce fluid from theformation. Migration inhibition wells 924 may be placed in formationthat is below pyrolysis and/or dissociation temperatures of minerals inthe formation.

In some embodiments, one or more of the migration inhibition wells 924include heaters. The heaters may be used to heat portions of theformation adjacent to the wells to a relatively low temperature. Therelatively low temperature may be a temperature below a dissociationtemperature of minerals in the formation adjacent to the well or below apyrolysis temperature of hydrocarbons in the formation. The temperaturethat the low temperature heater wells raise the formation to may be lessthan 260° C., less than 230° C., or less than 200° C. In someembodiments, heating elements in low temperature wells 924 may betailored so that the heating elements only heat portions of theformation that have permeability sufficient to allow for the migrationof fluid (for example, fracture systems).

Some or all migration inhibition wells 924 may be injector wells thatallow for the introduction of a sweep fluid into the formation. Theinjector wells may include smart well technology. Sweep fluid may beintroduced into the formation through critical orifices, perforations orother types of openings in the injector wells. In some embodiments, thesweep fluid is carbon dioxide. The carbon dioxide may be carbon dioxideproduced from an in situ heat treatment process. The sweep fluid may beor include other fluids, such as nitrogen, methane or othernon-condensable hydrocarbons, exhaust gases, air, and/or steam. Thesweep fluid may provide positive pressure in the formation outside oftreatment area 882. The positive pressure may inhibit migration offormation fluid from treatment area 882 towards barrier 922. The sweepfluid may move through fractures in the formation toward or intotreatment area 882. The sweep fluid may carry fluids that have migratedaway from treatment area 882 back to the treatment area. The pressure ofthe fluid introduced through migration inhibition wells 924 may bemaintained below the fracture pressure of the formation.

Alternative energy sources may be used to supply electricity forsubsurface electric heaters. Alternative energy sources include, but arenot limited to, wind, off-peak power, hydroelectric power, geothermal,solar, and tidal wave action. Some of these alternative energy sourcesprovide intermittent, time-variable power, or power-variable power. Toprovide power for subsurface electric heaters, power provided by thesealternative energy sources may be conditioned to produce power withappropriate operating parameters (for example, voltage, frequency,and/or current) for the subsurface heaters.

FIG. 135 illustrates a schematic of an embodiment using wind to generateelectricity for subsurface heaters. The generated electrical power maybe used to power other equipment used to treat a subsurface formationsuch as, but not limited to, pumps, computers, or other electricalequipment. In certain embodiments, windmill 926 is used to generateelectricity to power heaters 760. Windmill 926 may represent one or morewindmills in a wind farm. The windmills convert wind to a usablemechanical form of motion. In some embodiments, the wind farm mayinclude advanced windmills as suggested by the National Renewable EnergyLaboratory (Golden, Colo., U.S.A.). In some embodiments, windmill 926includes other intermittent, time-variable, or power-variable powersources.

In some embodiments, gas turbine 928 is used to generate electricity topower heaters 760. Windmill 926 and/or gas turbine 928 may be coupled totransformer 930. Transformer 930 may convert power from windmill 926and/or gas turbine 928 into electrical power with appropriate operatingparameters for heaters 760 (for example, AC or DC power with appropriatevoltage, current, and/or frequency may be generated by the transformer).

In certain embodiments, tap controller 932 is coupled to transformer930, control system 934 and heaters 760. Tap controller 932 may monitorand control transformer 930 to maintain a constant voltage to heaters760, regardless of the load of the heaters. Tap controller 932 maycontrol power output in a range from 5 MVA (megavolt amps) to 500 MVA,from 10 MVA to 400 MVA, or from 20 MVA to 300 MVA. As an example, duringoperation, an overload of voltage may be sent from transformer 930. Tapcontroller 932 may distribute the excess load to other heaters and/orother equipment in need of power. In some embodiments, tap controller932 may store the excess load for future use.

Control system 934 may control tap controller 932. Control system 934may be, for example, a computer controller or an analog logic system.Control system 934 may use data supplied from power sensors 936 togenerate predictive algorithms and/or control tap controller 932. Forexample, data may be an amount of power generated from windmill 926, gasturbine 928, and/or transformer 930. Data may also include an amount ofresistive load of heaters 760.

Automatic voltage regulation for resistive load of a heater maintainsthe life of the heaters and/or allows constant heat output from theheaters to a subsurface formation. Adjusting the load demands instead ofadjusting the power source allows enhanced control of power supplied toheaters and/or other equipment that requires electricity. Power suppliedto heaters 760 may be controlled within selected limits (for example, apower supplied and/or controlled to a heater within 1%, 5%, 10%, or 20%of power required by the heater). Control of power supplied fromalternative energy sources may allow output of prime power at itsrating, allow energy produced (for example, from an intermittent source,a subsurface formation, or a hydroelectric source) to be stored and usedlater, and/or allow use of power generated by intermittent power sourcesto be used as a constant source of energy.

Some hydrocarbon containing formations, such as oil shale formations,may include nahcolite, trona, dawsonite, and/or other minerals withinthe formation. In some embodiments, nahcolite is contained in partiallyunleached or unleached portions of the formation. Unleached portions ofthe formation are parts of the formation where minerals have not beenremoved by groundwater in the formation. For example, in the Piceancebasin in Colorado, U.S.A., unleached oil shale is found below a depth ofabout 500 m below grade. Deep unleached oil shale formations in thePiceance basin center tend to be relatively rich in hydrocarbons. Forexample, about 0.10 liters to about 0.15 liters of oil per kilogram(L/kg) of oil shale may be producible from an unleached oil shaleformation.

Nahcolite is a mineral that includes sodium bicarbonate (NaHCO₃).Nahcolite may be found in formations in the Green River lakebeds inColorado, U.S.A. In some embodiments, at least about 5 weight %, atleast about 10 weight %, or at least about 20 weight % nahcolite may bepresent in the formation. Dawsonite is a mineral that includes sodiumaluminum carbonate (NaAl(CO₃)(OH)₂). Dawsonite is typically present inthe formation at weight percents greater than about 2 weight % or, insome embodiments, greater than about 5 weight %. Nahcolite and/ordawsonite may dissociate at temperatures used in an in situ heattreatment process. The dissociation is strongly endothermic and mayproduce large amounts of carbon dioxide.

Nahcolite and/or dawsonite may be solution mined prior to, during,and/or following treatment of the formation in situ to avoiddissociation reactions and/or to obtain desired chemical compounds. Incertain embodiments, hot water or steam is used to dissolve nahcolite insitu to form an aqueous sodium bicarbonate solution before the in situheat treatment process is used to process hydrocarbons in the formation.Nahcolite may form sodium ions (Na⁺) and bicarbonate ions (HCO₃ ⁻) inaqueous solution. The solution may be produced from the formationthrough production wells, thus avoiding dissociation reactions duringthe in situ heat treatment process. In some embodiments, dawsonite isthermally decomposed to alumina during the in situ heat treatmentprocess for treating hydrocarbons in the formation. The alumina issolution mined after completion of the in situ heat treatment process.

Production wells and/or injection wells used for solution mining and/orfor in situ heat treatment processes may include smart well technology.The smart well technology allows the first fluid to be introduced at adesired zone in the formation. The smart well technology allows thesecond fluid to be removed from a desired zone of the formation.

Formations that include nahcolite and/or dawsonite may be treated usingthe in situ heat treatment process. A perimeter barrier may be formedaround the portion of the formation to be treated. The perimeter barriermay inhibit migration of water into the treatment area. During solutionmining and/or the in situ heat treatment process, the perimeter barriermay inhibit migration of dissolved minerals and formation fluid from thetreatment area. During initial heating, a portion of the formation to betreated may be raised to a temperature below the dissociationtemperature of the nahcolite. The temperature may be at most about 90°C., or in some embodiments, at most about 80° C. The temperature may beany temperature that increases the solvation rate of nahcolite in water,but is also below a temperature at which nahcolite dissociates (aboveabout 95° C. at atmospheric pressure).

A first fluid may be injected into the heated portion. The first fluidmay include water, brine, steam, or other fluids that form a solutionwith nahcolite and/or dawsonite. The first fluid may be at an increasedtemperature, for example, about 90° C., about 95° C., or about 100° C.The increased temperature may be similar to the temperature of theportion of the formation.

In some embodiments, the first fluid is injected at an increasedtemperature into a portion of the formation that has not been heated byheat sources. The increased temperature may be a temperature below aboiling point of the first fluid, for example, about 90° C. for water.Providing the first fluid at an increased temperature increases atemperature of a portion of the formation. In certain embodiments,additional heat may be provided from one or more heat sources in theformation during and/or after injection of the first fluid.

In other embodiments, the first fluid is or includes steam. The steammay be produced by forming steam in a previously heated portion of theformation (for example, by passing water through u-shaped wellbores thathave been used to heat the formation), by heat exchange with fluidsproduced from the formation, and/or by generating steam in standardsteam production facilities. In some embodiments, the first fluid may befluid introduced directly into a hot portion of the portion and producedfrom the hot portion of the formation. The first fluid may then be usedas the first fluid for solution mining.

In some embodiments, heat from a hot previously treated portion of theformation is used to heat water, brine, and/or steam used for solutionmining a new portion of the formation. Heat transfer fluid may beintroduced into the hot previously treated portion of the formation. Theheat transfer fluid may be water, steam, carbon dioxide, and/or otherfluids. Heat may transfer from the hot formation to the heat transferfluid. The heat transfer fluid is produced from the formation throughproduction wells. The heat transfer fluid is sent to a heat exchanger.The heat exchanger may heat water, brine, and/or steam used as the firstfluid to solution mine the new portion of the formation. The heattransfer fluid may be reintroduced into the heated portion of theformation to produce additional hot heat transfer fluid. In someembodiments, heat transfer fluid produced from the formation is treatedto remove hydrocarbons or other materials before being reintroduced intothe formation as part of a remediation process for the heated portion ofthe formation.

Steam injected for solution mining may have a temperature below thepyrolysis temperature of hydrocarbons in the formation. Injected steammay be at a temperature below 250° C., below 300° C., or below 400° C.The injected steam may be at a temperature of at least 150° C., at least135° C., or at least 125° C. Injecting steam at pyrolysis temperaturesmay cause problems as hydrocarbons pyrolyze and hydrocarbon fines mixwith the steam. The mixture of fines and steam may reduce permeabilityand/or cause plugging of production wells and the formation. Thus, theinjected steam temperature is selected to inhibit plugging of theformation and/or wells in the formation.

The temperature of the first fluid may be varied during the solutionmining process. As the solution mining progresses and the nahcolitebeing solution mined is farther away from the injection point, the firstfluid temperature may be increased so that steam and/or water thatreaches the nahcolite to be solution mined is at an elevated temperaturebelow the dissociation temperature of the nahcolite. The steam and/orwater that reaches the nahcolite is also at a temperature below atemperature that promotes plugging of the formation and/or wells in theformation (for example, the pyrolysis temperature of hydrocarbons in theformation).

A second fluid may be produced from the formation following injection ofthe first fluid into the formation. The second fluid may includematerial dissolved in the first fluid. For example, the second fluid mayinclude carbonic acid or other hydrated carbonate compounds formed fromthe dissolution of nahcolite in the first fluid. The second fluid mayalso include minerals and/or metals. The minerals and/or metals mayinclude sodium, aluminum, phosphorus, and other elements.

Solution mining the formation before the in situ heat treatment processallows initial heating of the formation to be provided by heat transferfrom the first fluid used during solution mining. Solution miningnahcolite or other minerals that decompose or dissociate by means ofendothermic reactions before the in situ heat treatment process avoidshaving energy supplied to heat the formation being used to support theseendothermic reactions. Solution mining allows for production of mineralswith commercial value. Removing nahcolite or other minerals before thein situ heat treatment process removes mass from the formation. Thus,less mass is present in the formation that needs to be heated to highertemperatures and heating the formation to higher temperatures may beachieved more quickly and/or more efficiently. Removing mass from theformation also may increase the permeability of the formation.Increasing the permeability may reduce the number of production wellsneeded for the in situ heat treatment process. In certain embodiments,solution mining before the in situ heat treatment process reduces thetime delay between startup of heating of the formation and production ofhydrocarbons by two years or more.

FIG. 136 depicts an embodiment of solution mining well 938. Solutionmining well 938 may include insulated portion 940, input 942, packer944, and return 946. Insulated portion 940 may be adjacent to overburden458 of the formation. In some embodiments, insulated portion 940 is lowconductivity cement. The cement may be low density, low conductivityvermiculite cement or foam cement. Input 942 may direct the first fluidto treatment area 882. Perforations or other types of openings in input942 allow the first fluid to contact formation material in treatmentarea 882. Packer 944 may be a bottom seal for input 942. First fluidpasses through input 942 into the formation. First fluid dissolvesminerals and becomes second fluid. The second fluid may be denser thanthe first fluid. An entrance into return 946 is typically located belowthe perforations or openings that allow the first fluid to enter theformation. Second fluid flows to return 946. The second fluid is removedfrom the formation through return 946.

FIG. 137 depicts a representation of an embodiment of solution miningwell 938. Solution mining well 938 may include input 942 and return 946in casing 948. Inlet 942 and/or return 946 may be coiled tubing.

FIG. 138 depicts a representation of an embodiment of solution miningwell 938. Insulating portions 940 may surround return 946. Input 942 maybe positioned in return 946. In some embodiments, input 942 mayintroduce the first fluid into the treatment area below the entry pointinto return 946. In some embodiments, crossovers may be used to directfirst fluid flow and second fluid flow so that first fluid is introducedinto the formation from input 942 above the entry point of second fluidinto return 946.

FIG. 139 depicts an elevational view of an embodiment of wells used forsolution mining and/or for an in situ heat treatment process. Solutionmining wells 938 may be placed in the formation in an equilateraltriangle pattern. In some embodiments, the spacing between solutionmining wells 938 may be about 36 m. Other spacings may be used. Heatsources 202 may also be placed in an equilateral triangle pattern.Solution mining wells 938 substitute for certain heat sources of thepattern. In the shown embodiment, the spacing between heat sources 202is about 9 m. The ratio of solution mining well spacing to heat sourcespacing is 4. Other ratios may be used if desired. After solution miningis complete, solution mining wells 938 may be used as production wellsfor the in situ heat treatment process.

In some formations, a portion of the formation with unleached mineralsmay be below a leached portion of the formation. The unleached portionmay be thick and substantially impermeable. A treatment area may beformed in the unleached portion. Unleached portion of the formation tothe sides, above and/or below the treatment area may be used as barriersto fluid flow into and out of the treatment area. A first treatment areamay be solution mined to remove minerals, increase permeability in thetreatment area, and/or increase the richness of the hydrocarbons in thetreatment area. After solution mining the first treatment area, in situheat treatment may be used to treat a second treatment area. In someembodiments, the second treatment area is the same as the firsttreatment area. In some embodiments, the second treatment has a smallervolume than the first treatment area so that heat provided by outermostheat sources to the formation do not raise the temperature of unleachedportions of the formation to the dissociation temperature of theminerals in the unleached portions.

In some embodiments, a leached or partially leached portion of theformation above an unleached portion of the formation may includesignificant amounts of hydrocarbon materials. An in situ heating processmay be used to produce hydrocarbon fluids from the unleached portionsand the leached or partially leached portions of the formation. FIG. 140depicts a representation of a formation with unleached zone 950 belowleached zone 952. Unleached zone 950 may have an initial permeabilitybefore solution mining of less than 0.1 millidarcy. Solution miningwells 938 may be placed in the formation. Solution mining wells 938 mayinclude smart well technology that allows the position of first fluidentrance into the formation and second flow entrance into the solutionmining wells to be changed. Solution mining wells 938 may be used toform first treatment area 882′ in unleached zone 950. Unleached zone 950may initially be substantially impermeable. Unleached portions of theformation may form a top barrier and side barriers around firsttreatment area 882′. After solution mining first treatment area 882′,the portions of solution mining wells 938 adjacent to the firsttreatment area may be converted to production wells and/or heater wells.

Heat sources 202 in first treatment area 882′ may be used to heat thefirst treatment area to pyrolysis temperatures. In some embodiments, oneor more heat sources 202 are placed in the formation before firsttreatment area 882′ is solution mined. The heat sources may be used toprovide initial heating to the formation to raise the temperature of theformation and/or to test the ftinctionality of the heat sources. In someembodiments, one or more heat sources are installed during solutionmining of the first treatment area, or after solution mining iscompleted. After solution mining, heat sources 202 may be used to raisethe temperature of at least a portion of first treatment area 882′ abovethe pyrolysis and/or mobilization temperature of hydrocarbons in theformation to result in the generation of mobile hydrocarbons in thefirst treatment area.

Barrier wells 200 may be introduced into the formation. Ends of barrierwells 200 may extend into and terminate in unleached zone 950. Unleachedzone 950 may be impermeable. In some embodiments, barrier wells 200 arefreeze wells. Barrier wells 200 may be used to form a barrier to fluidflow into or out of unleached zone 952. Barrier wells 200, overburden458, and the unleached material above first treatment area 882′ maydefine second treatment area 882″. In some embodiments, a first fluidmay be introduced into second treatment area 882″ through solutionmining wells 938 to raise the initial temperature of the formation insecond treatment area 882″ and remove any residual soluble minerals fromthe second treatment area. In some embodiments, the top barrier abovefirst treatment area 882′ may be solution mined to remove minerals andcombine first treatment area 882′ and second treatment area 882″ intoone treatment area. After solution mining, heat sources may be activatedto heat the treatment area to pyrolysis temperatures.

FIG. 141 depicts an embodiment for solution mining the formation.Barrier 922 (for example, a frozen barrier and/or a grout barrier) maybe formed around a perimeter of treatment area 882 of the formation. Thefootprint defined by the barrier may have any desired shape such ascircular, square, rectangular, polygonal, or irregular shape. Barrier922 may be any barrier formed to inhibit the flow of fluid into or outof treatment area 882. For example, barrier 922 may include one or morefreeze wells that inhibit water flow through the barrier. Barrier 922may be formed using one or more barrier wells 200. Formation of barrier922 may be monitored using monitor wells 956 and/or by monitoringdevices placed in barrier wells 200.

Water inside treatment area 882 may be pumped out of the treatment areathrough injection wells 748 and/or production wells 206. In certainembodiments, injection wells 748 are used as production wells 206 andvice versa (the wells are used as both injection wells and productionwells). Water may be pumped out until a production rate of water is lowor stops.

Heat may be provided to treatment area 882 from heat sources 202. Heatsources may be operated at temperatures that do not result in thepyrolysis of hydrocarbons in the formation adjacent to the heat sources.In some embodiments, treatment area 882 is heated to a temperature fromabout 90° C. to about 120° C. (for example, a temperature of about 90°C., 95° C., 100° C., 110° C., or 120° C.). In certain embodiments, heatis provided to treatment area 882 from the first fluid injected into theformation. The first fluid may be injected at a temperature from about90° C. to about 120° C. (for example, a temperature of about 90° C., 95°C., 100° C., 110° C., or 120° C.). In some embodiments, heat sources 202are installed in treatment area 882 after the treatment area is solutionmined. In some embodiments, some heat is provided from heaters placed ininjection wells 748 and/or production wells 206. A temperature oftreatment area 882 may be monitored using temperature measurementdevices placed in monitoring wells 956 and/or temperature measurementdevices in injection wells 748, production wells 206, and/or heatsources 202.

The first fluid is injected through one or more injection wells 748. Insome embodiments, the first fluid is hot water. The first fluid may mixand/or combine with non-hydrocarbon material that is soluble in thefirst fluid, such as nahcolite, to produce a second fluid. The secondfluid may be removed from the treatment area through injection wells748, production wells 206, and/or heat sources 202. Injection wells 748,production wells 206, and/or heat sources 202 may be heated duringremoval of the second fluid. Heating one or more wells during removal ofthe second fluid may maintain the temperature of the fluid duringremoval of the fluid from the treatment area above a desired value.After producing a desired amount of the soluble non-hydrocarbon materialfrom treatment area 882, solution remaining within the treatment areamay be removed from the treatment area through injection wells 748,production wells 206, and/or heat sources 202. The desired amount of thesoluble non-hydrocarbon material may be less than half of the solublenon-hydrocarbon material, a majority of the soluble non-hydrocarbonmaterial, substantially all of the soluble non-hydrocarbon material, orall of the soluble non-hydrocarbon material. Removing solublenon-hydrocarbon material may produce a relatively high permeabilitytreatment area 882.

Hydrocarbons within treatment area 882 may be pyrolyzed and/or producedusing the in situ heat treatment process following removal of solublenon-hydrocarbon materials. The relatively high permeability treatmentarea allows for easy movement of hydrocarbon fluids in the formationduring in situ heat treatment processing. The relatively highpermeability treatment area provides an enhanced collection area forpyrolyzed and mobilized fluids in the formation. During the in situ heattreatment process, heat may be provided to treatment area 882 from heatsources 202. A mixture of hydrocarbons may be produced from theformation through production wells 206 and/or heat sources 202. Incertain embodiments, injection wells 748 are used as either productionwells and/or heater wells during the in situ heat treatment process.

In some embodiments, a controlled amount of oxidant (for example, airand/or oxygen) is provided to treatment area 882 at or near heat sources202 when a temperature in the formation is above a temperaturesufficient to support oxidation of hydrocarbons. At such a temperature,the oxidant reacts with the hydrocarbons to provide heat in addition toheat provided by electrical heaters in heat sources 202. The controlledamount of oxidant may facilitate oxidation of hydrocarbons in theformation to provide additional heat for pyrolyzing hydrocarbons in theformation. The oxidant may more easily flow through treatment area 882because of the increased permeability of the treatment area afterremoval of the non-hydrocarbon materials. The oxidant may be provided ina controlled manner to control the heating of the formation. The amountof oxidant provided is controlled so that uncontrolled heating of theformation is avoided. Excess oxidant and combustion products may flow toproduction wells in treatment area 882.

Following the in situ heat treatment process, treatment area 882 may becooled by introducing water to produce steam from the hot portion of theformation. Introduction of water to produce steam may vaporize somehydrocarbons remaining in the formation. Water may be injected throughinjection wells 748. The injected water may cool the formation. Theremaining hydrocarbons and generated steam may be produced throughproduction wells 206 and/or heat sources 202. Treatment area 882 may becooled to a temperature near the boiling point of water. The steamproduced from the formation may be used to heat a first fluid used tosolution mine another portion of the formation.

Treatment area 882 may be further cooled to a temperature at which waterwill condense in the formation. Water and/or solvent may be introducedinto and be removed from the treatment area. Removing the condensedwater and/or solvent from treatment area 882 may remove any additionalsoluble material remaining in the treatment area. The water and/orsolvent may entrain non-soluble fluid present in the formation. Fluidmay be pumped out of treatment area 882 through production well 206and/or heat sources 202. The injection and removal of water and/orsolvent may be repeated until a desired water quality within treatmentarea 882 is achieved. Water quality may be measured at injection wells748, heat sources 202, and/or production wells 206. The water qualitymay substantially match or exceed the water quality of treatment area882 prior to treatment.

In some embodiments, treatment area 882 may include a leached zonelocated above an unleached zone. The leached zone may have been leachednaturally and/or by a separate leaching process. In certain embodiments,the unleached zone may be at a depth of at least about 500 m. Athickness of the unleached zone may be between about 100 m and about 500m. However, the depth and thickness of the unleached zone may varydepending on, for example, a location of treatment area 882 and/or thetype of formation. In certain embodiments, the first fluid is injectedinto the unleached zone below the leached zone. Heat may also beprovided into the unleached zone.

In certain embodiments, a section of a formation may be left untreatedby solution mining and/or unleached. The unleached section may beproximate a selected section of the formation that has been leachedand/or solution mined by providing the first fluid as described above.The unleached section may inhibit the flow of water into the selectedsection. In some embodiments, more than one unleached section may beproximate a selected section.

Nahcolite may be present in the formation in layers or beds. Prior tosolution mining, such layers may have little or no permeability. Incertain embodiments, solution mining layered or bedded nahcolite fromthe formation causes vertical shifting in the formation. FIG. 142depicts an embodiment of a formation with nahcolite layers in theformation below overburden 458 and before solution mining nahcolite fromthe formation. Hydrocarbon layers 460A have substantially no nahcoliteand hydrocarbon layers 460B have nahcolite. FIG. 143 depicts theformation of FIG. 142 after the nahcolite has been solution mined.Layers 460B have collapsed due to the removal of the nahcolite from thelayers. The collapsing of layers 460B causes compaction of the layersand vertical shifting of the formation. The hydrocarbon richness oflayers 460B is increased after compaction of the layers. In addition,the permeability of layers 460B may remain relatively high aftercompaction due to removal of the nahcolite. The permeability may be morethan 5 darcy, more than 1 darcy, or more than 0.5 darcy after verticalshifting. The permeability may provide fluid flow paths to productionwells when the formation is treated using an in situ heat treatmentprocess. The increased permeability may allow for a large spacingbetween production wells. Distances between production wells for the insitu heat treatment system after solution mining may be greater than 10m, greater than 20 m, or greater than 30 meters. Heater wells may beplaced in the formation after removal of nahcolite and the subsequentvertical shifting. Forming heater wellbores and/or installing heaters inthe formation after the vertical shifting protects the heaters frombeing damaged due to the vertical shifting.

In certain embodiments, removing nahcolite from the formationinterconnects two or more wells in the formation. Removing nahcolitefrom zones in the formation may increase the permeability in the zones.Some zones may have more nahcolite than others and become more permeableas the nahcolite is removed. At a certain time, zones with the increasedpermeability may interconnect two or more wells (for example, injectionwells or production wells) in the formation.

FIG. 144 depicts an embodiment of two injection wells interconnected bya zone that has been solution mined to remove nahcolite from the zone.Solution mining wells 938 are used to solution mine hydrocarbon layer460, which contains nahcolite. During the initial portion of thesolution mining process, solution mining wells 938 are used to injectwater and/or other fluids, and to produce dissolved nahcolite fluidsfrom the formation. Each solution mining well 938 is used to injectwater and produce fluid from a near wellbore region as the permeabilityof hydrocarbon layer is not sufficient to allow fluid to flow betweenthe injection wells. In certain embodiments, zone 958 has more nahcolitethan other portions of hydrocarbon layer 460. With increased nahcoliteremoval from zone 958, the permeability of the zone may increase. Thepermeability increases from the wellbores outwards as nahcolite isremoved from zone 958. At some point during solution mining of theformation, the permeability of zone 958 increases to allow solutionmining wells 938 to become interconnected such that fluid will flowbetween the wells. At this time, one solution mining well may be used toinject water while the other solution mining well is used to producefluids from the formation in a continuous process. Injecting in one welland producing from a second well may be more economical and moreefficient in removing nahcolite, as compared to injecting and producingthrough the same well. In some embodiments, additional wells may bedrilled into zone 958 and/or hydrocarbon layer 460 in addition tosolution mining wells 938. The additional wells may be used to circulateadditional water and/or to produce fluids from the formation. The wellsmay later be used as heater wells and/or production wells for the insitu heat treatment process treatment of hydrocarbon layer 460.

In some embodiments, the second fluid produced from the formation duringsolution mining is used to produce sodium bicarbonate. Sodiumbicarbonate may be used in the food and pharmaceutical industries, inleather tanning, in fire retardation, in wastewater treatment, and influe gas treatment (flue gas desulphurization and hydrogen chloridereduction). The second fluid may be kept pressurized and at an elevatedtemperature when removed from the formation. The second fluid may becooled in a crystallizer to precipitate sodium bicarbonate.

In some embodiments, the second fluid produced from the formation duringsolution mining is used to produce sodium carbonate, which is alsoreferred to as soda ash. Sodium carbonate may be used in the manufactureof glass, in the manufacture of detergents, in water purification,polymer production, tanning, paper manufacturing, effluentneutralization, metal refining, sugar extraction, and/or cementmanufacturing. The second fluid removed from the formation may be heatedin a treatment facility to form sodium carbonate (soda ash) and/orsodium carbonate brine. Heating sodium bicarbonate will form sodiumcarbonate according to the equation:2NaHCO₃→Na₂CO₃+CO₂+H₂O.  (7)

In certain embodiments, the heat for heating the sodium bicarbonate isprovided using heat from the formation. For example, a heat exchangerthat uses steam produced from the water introduced into the hotformation may be used to heat the second fluid to dissociationtemperatures of the sodium bicarbonate. In some embodiments, the secondfluid is circulated through the formation to utilize heat in theformation for further reaction. Steam and/or hot water may also be addedto facilitate circulation. The second fluid may be circulated through aheated portion of the formation that has been subjected to the in situheat treatment process to produce hydrocarbons from the formation. Atleast a portion of the carbon dioxide generated during sodium carbonatedissociation may be adsorbed on carbon that remains in the formationafter the in situ heat treatment process. In some embodiments, thesecond fluid is circulated through conduits previously used to heat theformation.

In some embodiments, higher temperatures are used in the formation (forexample, above about 120° C., above about 130° C., above about 150° C.,or below about 250° C.) during solution mining of nahcolite. The firstfluid is introduced into the formation under pressure sufficient toinhibit sodium bicarbonate from dissociating to produce carbon dioxide.The pressure in the formation may be maintained at sufficiently highpressures to inhibit such nahcolite dissociation but below pressuresthat would result in fracturing the formation. In addition, the pressurein the formation may be maintained high enough to inhibit steamformation if hot water is being introduced in the formation. In someembodiments, a portion of the nahcolite may begin to decompose in situ.In such cases, nahcolite is removed from the formation as soda ash. Ifsoda ash is produced from solution mining of nahcolite, the soda ash maybe transported to a separate facility for treatment. The soda ash may betransported through a pipeline to the separate facility.

As described above, in certain embodiments, following removal ofnahcolite from the formation, the formation is treated using the in situheat treatment process to produce formation fluids from the formation.If dawsonite is present in the formation, dawsonite within the heatedportion of the formation decomposes during heating of the formation topyrolysis temperature. Dawsonite typically decomposes at temperaturesabove 270° C. according to the reaction:2NaAl(OH)₂CO₃→Na₂CO₃+Al₂O₃+2H₂O+CO₂.  (8)

Sodium carbonate may be removed from the formation by solution miningthe formation with water or other fluid into which sodium carbonate issoluble. In certain embodiments, alumina formed by dawsonitedecomposition is solution mined using a chelating agent. The chelatingagent may be injected through injection wells, production wells, and/orheater wells used for solution mining nahcolite and/or the in situ heattreatment process (for example, injection wells 748, production wells206, and/or heat sources 202 depicted in FIG. 141). The chelating agentmay be an aqueous acid. In certain embodiments, the chelating agent isEDTA (ethylenediaminetetraacetic acid). Other examples of possiblechelating agents include, but are not limited to, ethylenediamine,porphyrins, dimercaprol, nitrilotriacetic acid,diethylenetriaminepentaacetic acid, phosphoric acids, acetic acid,acetoxy benzoic acids, nicotinic acid, pyruvic acid, citric acid,tartaric acid, malonic acid, imidizole, ascorbic acid, phenols, hydroxyketones, sebacic acid, and boric acid. The mixture of chelating agentand alumina may be produced through production wells or other wells usedfor solution mining and/or the in situ heat treatment process (forexample, injection wells 748, production wells 206, and/or heat sources202, which are depicted in FIG. 141). The alumina may be separated fromthe chelating agent in a treatment facility. The recovered chelatingagent may be recirculated back to the formation to solution mine morealumina.

In some embodiments, alumina within the formation may be solution minedusing a basic fluid after the in situ heat treatment process. Basicfluids include, but are not limited to, sodium hydroxide, ammonia,magnesium hydroxide, magnesium carbonate, sodium carbonate, potassiumcarbonate, pyridine, and amines. In an embodiment, sodium carbonatebrine, such as 0.5 Normal Na₂CO₃, is used to solution mine alumina.Sodium carbonate brine may be obtained from solution mining nahcolitefrom the formation. Obtaining the basic fluid by solution mining thenahcolite may significantly reduce costs associated with obtaining thebasic fluid. The basic fluid may be injected into the formation througha heater well and/or an injection well. The basic fluid may combine withalumina to form an alumina solution that is removed from the formation.The alumina solution may be removed through a heater well, injectionwell, or production well.

Alumina may be extracted from the alumina solution in a treatmentfacility. In an embodiment, carbon dioxide is bubbled through thealumina solution to precipitate the alumina from the basic fluid. Carbondioxide may be obtained from dissociation of nahcolite, from the in situheat treatment process, or from decomposition of the dawsonite duringthe in situ heat treatment process.

In certain embodiments, a formation may include portions that aresignificantly rich in either nahcolite or dawsonite only. For example, aformation may contain significant amounts of nahcolite (for example, atleast about 20 weight %, at least about 30 weight %, or at least about40 weight %) in a depocenter of the formation. The depocenter maycontain only about 5 weight % or less dawsonite on average. However, inbottom layers of the formation, a weight percent of dawsonite may beabout 10 weight % or even as high as about 25 weight %. In suchformations, it may be advantageous to solution mine for nahcolite onlyin nahcolite-rich areas, such as the depocenter, and solution mine fordawsonite only in the dawsonite-rich areas, such as the bottom layers.This selective solution mining may significantly reduce fluid costs,heating costs, and/or equipment costs associated with operating thesolution mining process.

In certain formations, dawsonite composition varies between layers inthe formation. For example, some layers of the formation may havedawsonite and some layers may not. In certain embodiments, more heat isprovided to layers with more dawsonite than to layers with lessdawsonite. Tailoring heat input to provide more heat to certaindawsonite layers more uniformly heats the formation as the reaction todecompose dawsonite absorbs some of the heat intended for pyrolyzinghydrocarbons. FIG. 145 depicts an embodiment for heating a formationwith dawsonite in the formation. Hydrocarbon layer 460 may be cored toassess the dawsonite composition of the hydrocarbon layer. The mineralcomposition may be assessed using, for example, FTIR (Fourier transforminfrared spectroscopy) or x-ray diffraction. Assessing the corecomposition may also assess the nahcolite composition of the core. Afterassessing the dawsonite composition, heater 716 may be placed inwellbore 452. Heater 716 includes sections to provide more heat tohydrocarbon layers with more dawsonite in the layers (hydrocarbon layers460D). Hydrocarbon layers with less dawsonite (hydrocarbon layers 460C)are provided with less heat by heater 716. Heat output of heater 716 maybe tailored by, for example, adjusting the resistance of the heateralong the length of the heater. In one embodiment, heater 716 is atemperature limited heater, described herein, that has a highertemperature limit (for example, higher Curie temperature) in sectionsproximate layers 460D as compared to the temperature limit (Curietemperature) of sections proximate layers 460C. The resistance of heater716 may also be adjusted by altering the resistive conducting materialsalong the length of the heater to supply a higher energy input (wattsper meter) adjacent to dawsonite rich layers.

Solution mining dawsonite and nahcolite may be relatively simpleprocesses that produce alumina and soda ash from the formation. In someembodiments, hydrocarbons produced from the formation using the in situheat treatment process may be fuel for a power plant that producesdirect current (DC) electricity at or near the site of the in situ heattreatment process. The produced DC electricity may be used on the siteto produce aluminum metal from the alumina using the Hall process.Aluminum metal may be produced from the alumina by melting the aluminain a treatment facility on the site. Generating the DC electricity atthe site may save on costs associated with using hydrotreaters,pipelines, or other treatment facilities associated with transportingand/or treating hydrocarbons produced from the formation using the insitu heat treatment process.

In some embodiments, acid may be introduced into the formation throughselected wells to increase the porosity adjacent to the wells. Forexample, acid may be injected if the formation comprises limestone ordolomite. The acid used to treat the selected wells may be acid producedduring in situ heat treatment of a section of the formation (forexample, hydrochloric acid), or acid produced from byproducts of the insitu heat treatment process (for example, sulfuric acid produced fromhydrogen sulfide or sulfur).

In some embodiments, a perimeter barrier may be formed around theportion of the formation to be treated. The perimeter barrier mayinhibit migration of formation fluid into or out of the treatment area.The perimeter barrier may be a frozen barrier and/or a grout barrier.After formation of the perimeter barrier, the treatment area may beprocessed to produce desired products.

Formations that include non-hydrocarbon materials may be treated toremove and/or dissolve a portion of the non-hydrocarbon materials from asection of the formation before hydrocarbons are produced from thesection. In some embodiments, the non-hydrocarbon materials are removedby solution mining. Removing a portion of the non-hydrocarbon materialsmay reduce the carbon dioxide generation sources present in theformation. Removing a portion of the non-hydrocarbon materials mayincrease the porosity and/or permeability of the section of theformation. Removing a portion of the non-hydrocarbon materials mayresult in a raised temperature in the section of the formation.

After solution mining, some of the wells in the treatment may beconverted to heater wells, injection wells, and/or production wells. Insome embodiments, additional wells are formed in the treatment area. Thewells may be heater wells, injection wells, and/or production wells.Logging techniques may be employed to assess the physicalcharacteristics, including any vertical shifting resulting from thesolution mining, and/or the composition of material in the formation.Packing, baffles or other techniques may be used to inhibit formationfluid from entering the heater wells. The heater wells may be activatedto heat the formation to a temperature sufficient to support combustion.

One or more production wells may be positioned in permeable sections ofthe treatment area. Production wells may be horizontally and/orvertically oriented. For example, production wells may be positioned inareas of the formation that have a permeability of greater than 5 darcyor 10 darcy. In some embodiments, production wells may be positionednear a perimeter barrier. A production well may allow water andproduction fluids to be removed from the formation. Positioning theproduction well near a perimeter barrier enhances the flow of fluidsfrom the warmer zones of the formation to the cooler zones.

FIG. 146 depicts an embodiment of a process for treating a hydrocarboncontaining formation with a combustion front. Barrier 922 (for example,a frozen barrier or a grout barrier) may be formed around a perimeter oftreatment area 882 of the formation. The footprint define by the barriermay have any desired shape such as circular, square, rectangular,polygonal, or irregular shape. Barrier 922 may be formed using one ormore barrier wells 200. The barrier may be any barrier formed to inhibitthe flow of fluid into or out of treatment area 882. In someembodiments, barrier 922 may be a double barrier.

Heat may be provided to treatment area 882 through heaters positioned ininjection wells 748. In some embodiments, the heaters in injection wells748 heat formation adjacent to the injections wells to temperaturessufficient to support combustion. Heaters in injection wells 748 mayraise the formation near the injection wells to temperatures from about90° C. to about 120° C. or higher (for example, a temperature of about90° C., 95° C., 100° C., 110° C., or 120° C.).

Injection wells 748 may be used to introduce a combustion fuel, anoxidant, steam and/or a heat transfer fluid into treatment area 882,either before, during, or after heat is provided to the treatment area882 from heaters. In some embodiments, injection wells 748 are incommunication with each other to allow the introduced fluid to flow fromone well to another. Injection wells 748 may be located at positionsthat are relatively far away from perimeter barrier 922. Introducedfluid may cause combustion of hydrocarbons in treatment area 882. Heatfrom the combustion may heat treatment area 882 and mobilize fluidstoward production wells 206.

A temperature of treatment area 882 may be monitored using temperaturemeasurement devices placed in monitoring wells and/or temperaturemeasurement devices in injection wells 748, production wells 206, and/orheater wells.

In some embodiments, a controlled amount of oxidant (for example, airand/or oxygen) is provided in injection wells 748 to advance a heatfront towards production wells 206. In some embodiments, the controlledamount of oxidant is introduced into the formation after solution mininghas established permeable interconnectivity between at least twoinjection wells. The amount of oxidant is controlled to limit theadvancement rate of the heat front and to limit the temperature of theheat front. The advancing heat front may pyrolyze hydrocarbons. The highpermeability in the formation allows the pyrolyzed hydrocarbons tospread in the formation towards production wells without being overtakenby the advancing heat front.

Vaporized formation fluid and/or gas formed during the combustionprocess may be removed through gas wells 960 and/or injection well 748.Venting of gases through the gas wells and/or the injection well mayforce the combustion front in a desired direction.

In some embodiments, the formation may be heated to a temperaturesufficient to cause pyrolysis of the formation fluid by the steam and/orheat transfer fluid. The steam and/or heat transfer fluid may be heatedto temperatures of about 300° C., about 400° C., about 500° C., or about600° C. In certain embodiments, the steam and/or heat transfer fluid maybe co-injected with the fuel and/or oxidant.

FIG. 147 depicts a representation of a cross-sectional view of anembodiment for treating a hydrocarbon containing formation with acombustion front. As the combustion front is initiated and/or fueledthrough injection wells 748, formation fluid near periphery 962 of thecombustion front becomes mobile and flow towards production wells 206located proximate barrier 922. Injection wells may include smart welltechnology. Combustion products and noncondensable formation fluid maybe removed from the formation through gas wells 960. In someembodiments, no gas wells are formed in the formation. In suchembodiments, formation fluid, combustion products and noncondensableformation fluid are produced through production wells 206. Inembodiments that include gas wells 960, condensable formation fluid maybe produced through production well 206. In some embodiments, productionwell 206 is located below injection well 748. Production well 206 may beabout 1 m, 5 m, to 10 m or more below injection well 748. Productionwell may be a horizontal well. Periphery 962 of the combustion front mayadvance from the toe of production well 206 towards the heel of theproduction well. Production well 206 may include a perforated liner thatallows hydrocarbons to flow into the production well. In someembodiments, a catalyst may be placed in production well 206. Thecatalyst may upgrade and/or stabilize formation fluid in the productionwell.

Carbon dioxide and/or hydrogen sulfide may be produced during in situheat treatment processes and during many conventional productionprocesses. Removal of hydrogen sulfide from produced formation fluid mayreduce the toxicity and/or strong odor in the produced formation fluid,thus making the formation fluid more acceptable for transportationand/or processing. Removing carbon dioxide and/or hydrogen sulfide fromproduced formation fluids may reduce capital costs associated withremoving the fluids and reduce or eliminate the need for certain surfacefacilities (for example, a Claus plant or Scot gas treater). Sincecarbon dioxide has a low heating value, removal of carbon dioxide fromformation fluids may increase the heat capacity of a gas streamseparated from the formation fluid.

Net release of carbon dioxide to the atmosphere and/or hydrogen sulfideconversion to sulfur from an in situ heat treatment process forhydrocarbons may be reduced by utilizing the produced carbon dioxideand/or by storing carbon dioxide and/or hydrogen sulfide within theformation or within another formation. Carbon dioxide and/or hydrogensulfide may be introduced into a portion of the formation belowtreatment areas subjected to in situ heat treatment processes. In someembodiments, the carbon dioxide and/or hydrogen sulfide may betransported to another formation.

In certain embodiments, carbon dioxide and/or hydrogen sulfide may bestored in spent portions of formations that have previously beensubjected to in situ heat treatment processes or other hydrocarbonrecovery processes. Carbon dioxide may absorb on or into remainingcarbon containing material in such formations.

In certain embodiments, carbon dioxide and/or hydrogen sulfide is storedin a porous, deep saline aquifer. The carbon dioxide and/or hydrogensulfide may promote mineralization within the aquifer. For example, theintroduction of carbon dioxide and hydrogen sulfide into a salineaquifer may result in the production of carbonates in the aquifer. Incertain embodiments, carbon dioxide is stored at a depth in theformation such that the carbon dioxide is introduced in the formation ina supercritical state. Supercritical carbon dioxide injection maymaximize the density of the fluid introduced into the formation. Thedepths of outlets of insertion wells used to introduce carbon dioxideand/or hydrogen sulfide in the formation may be 900 m or more below thesurface. The injection wells may be vertical, slanted, or directionallysteered wells with a significant horizontal or near horizontal portion.The carbon dioxide and/or hydrogen sulfide may be introduced into theformation near the bottom of the saline aquifer.

Injection of carbon dioxide and/or hydrogen sulfide into a non-producingformation or using the carbon dioxide and/or hydrogen sulfide as a floodfluid is described by Caroll in “Physical Properties Relevant to AcidGas Injection,” Presented at the 14th International Gas ConventionVenezuelan Gas Processors Association on May 10-12, 2000 in Caracas,Venezuela; “Phase Equilibria Relevant to Acid Gas Injection: Part1-Non-Aqueoues Phase Behaviour Journal of Canadian Petroleum Technology,2002, Vol. 41 No. 6, pp. 1-6; and “Phase Equilibria Relevant to Acid GasInjection: Part 2-Aqueoues Phase Behaviour Journal of Canadian PetroleumTechnology, 2002, Vol. 41, No. 7, pp. 1-5, all of which are incorporatedby reference as if fully set forth herein.

During production of formation fluids from a subsurface formation,carbonic acid may be produced from the reaction of carbon dioxide withwater. Portions of wells made of certain materials, such as carbonsteel, may start to deteriorate or corrode in the presence of thecarbonic acid. To inhibit corrosion due to carbonic acid, basicsolutions and/or solvents may be introduced in the wellbore toneutralize and/or dissolve the carbonic acid.

In some embodiments, hydrogen sulfide is introduced into one or morewellbores in a subsurface formation. Introduction of the hydrogensulfide may be performed at pressures below the lithostatic pressure ofthe subsurface formation to inhibit fracturing the formation. Theinjected hydrogen sulfide may form a sulfide layer on metal surfaces ofthe well. Formation of a sulfide layer may inhibit corrosion of themetal surfaces of the well by carbonic acid.

In certain embodiments, an electrical insulator (for example, acentralizer, an insulating layer, the electrical insulator in aninsulated conductor heater, or any other electrical insulator describedherein) includes a material that is fired or cured when heated in thesubsurface. The material may develop desired dielectric or otherelectrical properties and/or physical properties after the material isfired or cured in a wellbore in the formation. The material may be firedor cured when a heater is turned on in the wellbore and the heater heatsthe material to its firing or curing temperature.

An example of such a material is a ceramic tape available from CompositeDevelopment Technology, Inc. (Lafayette, Colo., U.S.A.). The ceramictape is flexible before it is fired. The ceramic tape obtains itsdielectric properties after firing. After firing, the ceramic tape is ahard-ceramic with good dielectric properties suitable for subsurfaceelectrical heating.

In an embodiment, the ceramic tape is wrapped around an electricalconductor (for example, the conductor of a temperature limited heater).Electrical current may be applied to the electrical conductor to heatthe heater and fire the ceramic tape. In some embodiments, the ceramictape is pre-fired before installation of a heater. The ceramic tape maybe pre-fired using, for example, a hot gas gun.

Before firing, the ceramic tape is flexible and easy to install in avariety of applications. In certain embodiments, the ceramic tape isused between centralizers in a conductor-in-conduit heater. The ceramictape may inhibit shorting of the conductor and conduit if thecentralizers fail (for example, if the centralizers buckle and fail). Incertain embodiments, the ceramic tape is used as the centralizers in aconductor-in-conduit heater. In some embodiments, the ceramic tape isused as the electrical insulator in an insulated conductor heater. Insome embodiments, the ceramic tape is used as the electrical insulatorin splices between sections of heaters. In some embodiments, the ceramictape is used to electrically insulate the legs of a three-phase heater.The three legs of the three-phase heater may be enclosed in one sheathwith the ceramic tape separating the legs of the heater.

Non-restrictive examples are set forth below.

Temperature Limited Heater Experimental Data

FIGS. 148-163 depict experimental data for temperature limited heaters.FIG. 148 depicts electrical resistance (Ω) versus temperature (° C.) atvarious applied electrical currents for a 446 stainless steel rod with adiameter of 2.5 cm and a 410 stainless steel rod with a diameter of 2.5cm. Both rods had a length of 1.8 m. Curves 964-970 depict resistanceprofiles as a function of temperature for the 446 stainless steel rod at440 amps AC (curve 964), 450 amps AC (curve 966), 500 amps AC (curve968), and 10 amps DC (curve 970). Curves 972-978 depict resistanceprofiles as a function of temperature for the 410 stainless steel rod at400 amps AC (curve 972), 450 amps AC (curve 974), 500 amps AC (curve976), 10 amps DC (curve 978). For both rods, the resistance graduallyincreased with temperature until the Curie temperature was reached. Atthe Curie temperature, the resistance fell sharply. Above the Curietemperature, the resistance decreased slightly with increasingtemperature. Both rods show a trend of decreasing resistance withincreasing AC current. Accordingly, the turndown ratio decreased withincreasing current. Thus, the rods provide a reduced amount of heat nearand above the Curie temperature of the rods. In contrast, the resistancegradually increased with temperature through the Curie temperature withthe applied DC current.

FIG. 149 shows electrical resistance (Ω) profiles as a function oftemperature (° C.) at various applied electrical currents for a copperrod contained in a conduit of Sumitomo HCM12A (a high strength 410stainless steel). The Sumitomo conduit had a diameter of 5.1 cm, alength of 1.8 m, and a wall thickness of about 0.1 cm. Curves 980-990show that at all applied currents (980: 300 amps AC; 982: 350 amps AC;984: 400 amps AC; 986: 450 amps AC; 988: 500 amps AC; 990: 550 amps AC),resistance increased gradually with temperature until the Curietemperature was reached. At the Curie temperature, the resistance fellsharply. As the current increased, the resistance decreased, resultingin a smaller turndown ratio.

FIG. 150 depicts electrical resistance (Ω) versus temperature (° C.) atvarious applied electrical currents for a temperature limited heater.The temperature limited heater included a 4/0 MGT-1000 furnace cableinside an outer conductor of ¾ Schedule 80 Sandvik (Sweden) 4C54 (446stainless steel) with a 0.30 cm thick copper sheat welded onto theoutside of the Sandvik 4C54 and a length of 1.8 m. Curves 1000 through1018 show resistance profiles as function of temperature for AC appliedcurrents ranging from 40 amps to 500 amps (1000: 40 amps; 1002: 80 amps;1004: 120 amps; 1006: 160 amps; 1008: 250 amps; 1010: 300 amps; 1012:350 amps; 1014: 400 amps; 1016: 450 amps; 1018: 500 amps). FIG. 151depicts the raw data for curve 1014. FIG. 152 depicts the data forselected curves 1010, 1012, 1014, 1016, 1018, and 1020. At lowercurrents (below 250 amps), the resistance increased with increasingtemperature up to the Curie temperature. At the Curie temperature, theresistance fell sharply. At higher currents (above 250 amps), theresistance decreased slightly with increasing temperature up to theCurie temperature. At the Curie temperature, the resistance fellsharply. Curve 1020 shows resistance for an applied DC electricalcurrent of 10 amps. Curve 1020 shows a steady increase in resistancewith increasing temperature, with little or no deviation at the Curietemperature.

FIG. 153 depicts power (watts per meter (W/m)) versus temperature (° C.)at various applied electrical currents for a temperature limited heater.The temperature limited heater included a 4/0 MGT-1000 furnace cableinside an outer conductor of ¾″ Schedule 80 Sandvik (Sweden) 4C54 (446stainless steel) with a 0.30 cm thick copper sheat welded onto theoutside of the Sandvik 4C54 and a length of 1.8 m. Curves 1022-1030depict power versus temperature for AC applied currents of 300 amps to500 amps (1022: 300 amps; 1024: 350 amps; 1026: 400 amps; 1028: 450amps; 1030: 500 amps). Increasing the temperature gradually decreasedthe power until the Curie temperature was reached. At the Curietemperature, the power decreased rapidly.

FIG. 154 depicts electrical resistance (mΩ) versus temperature (° C.) atvarious applied electrical currents for a temperature limited heater.The temperature limited heater included a copper rod with a diameter of1.3 cm inside an outer conductor of 2.5 cm Schedule 80 410 stainlesssteel pipe with a 0.15 cm thick copper Everdur™ (DuPont Engineering,Wilmington, Del., U.S.A.) welded sheath over the 410 stainless steelpipe and a length of 1.8 m. Curves 1032-1042 show resistance profiles asa function of temperature for AC applied currents ranging from 300 ampsto 550 amps (1032: 300 amps; 1034: 350 amps; 1036: 400 amps; 1038: 450amps; 1040: 500 amps; 1042: 550 amps). For these AC applied currents,the resistance gradually increases with increasing temperature up to theCurie temperature. At the Curie temperature, the resistance fallssharply. In contrast, curve 1044 shows resistance for an applied DCelectrical current of 10 amps. This resistance shows a steady increasewith increasing temperature, and little or no deviation at the Curietemperature.

FIG. 155 depicts data of electrical resistance (mΩ) versus temperature(° C.) for a solid 2.54 cm diameter, 1.8 m long 410 stainless steel rodat various applied electrical currents. Curves 1046, 1048, 1050, 1052,and 1054 depict resistance profiles as a function of temperature for the410 stainless steel rod at 40 amps AC (curve 1052), 70 amps AC (curve1054), 140 amps AC (curve 1046), 230 amps AC (curve 1048), and 10 ampsDC (curve 1050). For the applied AC currents of 140 amps and 230 amps,the resistance increased gradually with increasing temperature until theCurie temperature was reached. At the Curie temperature, the resistancefell sharply. In contrast, the resistance showed a gradual increase withtemperature through the Curie temperature for the applied DC current.

FIG. 156 depicts data of electrical resistance (mΩ) versus temperature(° C.) for a composite 1.75 inch (1.9 cm) diameter, 6 foot (1.8 m) longAlloy 42-6 rod with a 0.375 inch diameter copper core (the rod has anoutside diameter to copper diameter ratio of 2:1) at various appliedelectrical currents. Curves 1056, 1058, 1060, 1062, 1064, 1066, 1068,and 1070 depict resistance profiles as a function of temperature for thecopper cored alloy 42-6 rod at 300 A AC (curve 1056), 350 A AC (curve1058), 400 A AC (curve 1060), 450 A AC (curve 1062), 500 A AC (curve1064), 550 A AC (curve 1066), 600 A AC (curve 1068), and 10 A DC (curve1070). For the applied AC currents, the resistance decreased graduallywith increasing temperature until the Curie temperature was reached. Asthe temperature approaches the Curie temperature, the resistancedecreased more sharply. In contrast, the resistance showed a gradualincrease with temperature for the applied DC current.

FIG. 157 depicts data of power output (watts per foot (W/ft)) versustemperature (° C.) for a composite 1.75 inch (1.9 cm) diameter, 6 foot(1.8 m) long Alloy 42-6 rod with a 0.375 inch diameter copper core (therod has an outside diameter to copper diameter ratio of 2:1) at variousapplied electrical currents. Curves 1072, 1074, 1076, 1078, 1080, 1082,1084, and 1086 depict power as a function of temperature for the coppercored alloy 42-6 rod at 300 A AC (curve 1072), 350 A AC (curve 1074),400 A AC (curve 1076), 450 A AC (curve 1078), 500 A AC (curve 1080), 550A AC (curve 1082), 600 A AC (curve 1084), and 10 A DC (curve 1086). Forthe applied AC currents, the power output decreased gradually withincreasing temperature until the Curie temperature was reached. As thetemperature approaches the Curie temperature, the power output decreasedmore sharply. In contrast, the power output showed a relatively flatprofile with temperature for the applied DC current.

FIG. 158 depicts data for values of skin depth (cm) versus temperature(° C.) for a solid 2.54 cm diameter, 1.8 m long 410 stainless steel rodat various applied AC electrical currents. The skin depth was calculatedusing EQN. 9:δ=R ₁ −R ₁×(1−(1/R _(AC) /R _(DC)))^(1/2);  (9)where δ is the skin depth, R₁ is the radius of the cylinder, R_(AC) isthe AC resistance, and R_(DC) is the DC resistance. In FIG. 158, curves1088-1106 show skin depth profiles as a function of temperature forapplied AC electrical currents over a range of 50 amps to 500 amps(1088: 50 amps; 1090: 100 amps; 1092: 150 amps; 1094: 200 amps; 1096:250 amps; 1098: 300 amps; 1100: 350 amps; 1102: 400 amps; 1104: 450amps; 1106: 500 amps). For each applied AC electrical current, the skindepth gradually increased with increasing temperature up to the Curietemperature. At the Curie temperature, the skin depth increased sharply.

FIG. 159 depicts temperature (° C.) versus time (hrs) for a temperaturelimited heater. The temperature limited heater was a 1.83 m long heaterthat included a copper rod with a diameter of 1.3 cm inside a 2.5 cmSchedule XXH 410 stainless steel pipe and a 0.325 cm copper sheath. Theheater was placed in an oven for heating. Alternating current wasapplied to the heater when the heater was in the oven. The current wasincreased over two hours and reached a relatively constant value of 400amps for the remainder of the time. Temperature of the stainless steelpipe was measured at three points at 0.46 m intervals along the lengthof the heater. Curve 1108 depicts the temperature of the pipe at a point0.46 m inside the oven and closest to the lead-in portion of the heater.Curve 1110 depicts the temperature of the pipe at a point 0.46 m fromthe end of the pipe and furthest from the lead-in portion of the heater.Curve 1112 depicts the temperature of the pipe at about a center pointof the heater. The point at the center of the heater was furtherenclosed in a 0.3 m section of 2.5 cm thick Fiberfrax® (Unifrax Corp.,Niagara Falls, N.Y., U.S.A.) insulation. The insulation was used tocreate a low thermal conductivity section on the heater (a section whereheat transfer to the surroundings is slowed or inhibited (a “hotspot”)). The temperature of the heater increased with time as shown bycurves 1112, 1110, and 1108. Curves 1112, 1110, and 1108 show that thetemperature of the heater increased to about the same value for allthree points along the length of the heater. The resulting temperatureswere substantially independent of the added Fiberfrax® insulation. Thus,the operating temperatures of the temperature limited heater weresubstantially the same despite the differences in thermal load (due tothe insulation) at each of the three points along the length of theheater. Thus, the temperature limited heater did not exceed the selectedtemperature limit in the presence of a low thermal conductivity section.

FIG. 160 depicts temperature (° C.) versus log time (hrs) data for a 2.5cm solid 410 stainless steel rod and a 2.5 cm solid 304 stainless steelrod. At a constant applied AC electrical current, the temperature ofeach rod increased with time. Curve 1114 shows data for a thermocoupleplaced on an outer surface of the 304 stainless steel rod and under alayer of insulation. Curve 1116 shows data for a thermocouple placed onan outer surface of the 304 stainless steel rod without a layer ofinsulation. Curve 1118 shows data for a thermocouple placed on an outersurface of the 410 stainless steel rod and under a layer of insulation.Curve 1120 shows data for a thermocouple placed on an outer surface ofthe 410 stainless steel rod without a layer of insulation. A comparisonof the curves shows that the temperature of the 304 stainless steel rod(curves 1114 and 1116) increased more rapidly than the temperature ofthe 410 stainless steel rod (curves 1118 and 1120). The temperature ofthe 304 stainless steel rod (curves 1114 and 1116) also reached a highervalue than the temperature of the 410 stainless steel rod (curves 1118and 1120). The temperature difference between the non-insulated sectionof the 410 stainless steel rod (curve 1120) and the insulated section ofthe 410 stainless steel rod (curve 1118) was less than the temperaturedifference between the non-insulated section of the 304 stainless steelrod (curve 1116) and the insulated section of the 304 stainless steelrod (curve 1114). The temperature of the 304 stainles steel rod wasincreasing at the termination of the experiment (curves 1114 and 1116)while the temperature of the 410 stainless steel rod had leveled out(curves 1118 and 1120). Thus, the 410 stainless steel rod (thetemperature limited heater) provided better temperature control than the304 stainless steel rod (the non-temperature limited heater) in thepresence of varying thermal loads (due to the insulation).

A 6 foot temperature limited heater element was placed in a 6 foot 347Hstainless steel canister. The heater element was connected to thecanister in a series configuration. The heater element and canister wereplaced in an oven. The oven was used to raise the temperature of theheater element and the canister. At varying temperatures, a series ofelectrical currents were passed through the heater element and returnedthrough the canister. The resistance of the heater element and the powerfactor of the heater element were determined from measurements duringpassing of the electrical currents.

FIG. 161 depicts experimentally measured electrical resistance (mΩ)versus temperature (° C.) at several currents for a temperature limitedheater with a copper core, a carbon steel ferromagnetic conductor, and a347H stainless steel support member. The ferromagnetic conductor was alow-carbon steel with a Curie temperature of 770° C. The ferromagneticconductor was sandwiched between the copper core and the 347H supportmember. The copper core had a diameter of 0.5″. The ferromagneticconductor had an outside diameter of 0.765″. The support member had anoutside diameter of 1.05″. The canister was a 3″ Schedule 160 347Hstainless steel canister.

Data 1122 depicts electrical resistance versus temperature for 300 A at60 Hz AC applied current. Data 1124 depicts resistance versustemperature for 400A at 60 Hz AC applied current. Data 1126 depictsresistance versus temperature for 500A at 60 Hz AC applied current.Curve 1128 depicts resistance versus temperature for 10A DC appliedcurrent. The resistance versus temperature data indicates that the ACresistance of the temperature limited heater linearly increased up to atemperature near the Curie temperature of the ferromagnetic conductor.Near the Curie temperature, the AC resistance decreased rapidly untilthe AC resistance equaled the DC resistance above the Curie temperature.The linear dependence of the AC resistance below the Curie temperatureat least partially reflects the linear dependence of the AC resistanceof 347H at these temperatures. Thus, the linear dependence of the ACresistance below the Curie temperature indicates that the majority ofthe current is flowing through the 347H support member at thesetemperatures.

FIG. 162 depicts experimentally measured electrical resistance (mΩ)versus temperature (° C.) data at several currents for a temperaturelimited heater with a copper core, a iron-cobalt ferromagneticconductor, and a 347H stainless steel support member. The iron-cobaltferromagnetic conductor was an iron-cobalt conductor with 6% cobalt byweight and a Curie temperature of 834° C. The ferromagnetic conductorwas sandwiched between the copper core and the 347H support member. Thecopper core had a diameter of 0.465″. The ferromagnetic conductor had anoutside diameter of 0.765″. The support member had an outside diameterof 1.05″. The canister was a 3″ Schedule 160 347H stainless steelcanister.

Data 1130 depicts resistance versus temperature for 100 A at 60 Hz ACapplied current. Data 1132 depicts resistance versus temperature for 400A at 60 Hz AC applied current. Curve 1134 depicts resistance versustemperature for 10A DC. The AC resistance of this temperature limitedheater turned down at a higher temperature than the previous temperaturelimited heater. This was due to the added cobalt increasing the Curietemperature of the ferromagnetic conductor. The AC resistance wassubstantially the same as the AC resistance of a tube of 347H steelhaving the dimensions of the support member. This indicates that themajority of the current is flowing through the 347H support member atthese temperatures. The resistance curves in FIG. 162 are generally thesame shape as the resistance curves in FIG. 161.

FIG. 163 depicts experimentally measured power factor (y-axis) versustemperature (° C.) at two AC currents for the temperature limited heaterwith the copper core, the iron-cobalt ferromagnetic conductor, and the347H stainless steel support member. Curve 1136 depicts power factorversus temperature for 100A at 60 Hz AC applied current. Curve 1138depicts power factor versus temperature for 400A at 60 Hz AC appliedcurrent. The power factor was close to unity (1) except for the regionaround the Curie temperature. In the region around the Curietemperature, the non-linear magnetic properties and a larger portion ofthe current flowing through the ferromagnetic conductor produceinductive effects and distortion in the heater that lowers the powerfactor. FIG. 163 shows that the minimum value of the power factor forthis heater remained above 0.85 at all temperatures in the experiment.Because only portions of the temperature limited heater used to heat asubsurface formation may be at the Curie temperature at any given pointin time and the power factor for these portions does not go below 0.85during use, the power factor for the entire temperature limited heaterwould remain above 0.85 (for example, above 0.9 or above 0.95) duringuse.

From the data in the experiments for the temperature limited heater withthe copper core, the iron-cobalt ferromagnetic conductor, and the 347Hstainless steel support member, the turndown ratio (y-axis) wascalculated as a function of the maximum power (W/m) delivered by thetemperature limited heater. The results of these calculations aredepicted in FIG. 164. The curve in FIG. 164 shows that the turndownratio (y-axis) remains above 2 for heater powers up to approximately2000 W/m. This curve is used to determine the ability of a heater toeffectively provide heat output in a sustainable manner. A temperaturelimited heater with the curve similar to the curve in FIG. 164 would beable to provide sufficient heat output while maintaining temperaturelimiting properties that inhibit the heater from overheating ormalfunctioning.

A theoretical model has been used to predict the experimental results.The theoretical model is based on an analytical solution for the ACresistance of a composite conductor. The composite conductor has a thinlayer of ferromagnetic material, with a relative magnetic permeabilityμ₂/μ₀>>1, sandwiched between two non-ferromagnetic materials, whoserelative magnetic permeabilities, μ₁/μ₀ and μ₃/μ₀, are close to unityand within which skin effects are negligible. An assumption in the modelis that the ferromagnetic material is treated as linear. In addition,the way in which the relative magnetic permeability, μ₂/μ₀, is extractedfrom magnetic data for use in the model is far from rigorous.

Magnetic data was obtained for carbon steel as a ferromagnetic material.B versus H curves, and hence relative permeabilities, were obtained fromthe magnetic data at various temperatures up to 1100° F. and magneticfields up to 200 Oe (oersteds). A correlation was found that fitted thedata well through the maximum permeability and beyond. FIG. 165 depictsexamples of relative magnetic permeability (y-axis) versus magneticfield (Oe) for both the found correlations and raw data for carbonsteel. Data 1140 is raw data for carbon steel at 400° F. Data 1142 israw data for carbon steel at 1000° F. Curve 1144 is the foundcorrelation for carbon steel at 400° F. Curve 1146 is the foundcorrelation for carbon steel at 1000° F.

For the dimensions and materials of the copper/carbon steel/347H heaterelement in the experiments above, theoretical calculations were carriedout to calculate magnetic field at the outer surface of the carbon steelas a function of skin depth. Results of the theoretical calculationswere presented on the same plot as skin depth versus magnetic field fromthe correlations applied to the magnetic data from FIG. 165. Thetheoretical calculations and correlations were made for fourtemperatures (200° F., 500° F., 800° F., and 1100° F.) and five totalroot-mean-square (RMS) currents (100 A, 200 A, 300 A, 400 A, and 500 A).

FIG. 166 shows the resulting plots of skin depth (in) versus magneticfield (Oe) for all four temperatures and 400 A current. Curve 1148 isthe correlation from magnetic data at 200° F. Curve 1150 is thecorrelation from magnetic data at 500° F. Curve 1152 is the correlationfrom magnetic data at 800° F. Curve 1154 is the correlation frommagnetic data at 1100° F. Curve 1156 is the theoretical calculation atthe outer surface of the carbon steel as a function of skin depth at200° F. Curve 1158 is the theoretical calculation at the outer surfaceof the carbon steel as a function of skin depth at 500° F. Curve 1160 isthe theoretical calculation at the outer surface of the carbon steel asa function of skin depth at 800° F. Curve 1162 is the theoreticalcalculation at the outer surface of the carbon steel as a function ofskin depth at 1100° F.

The skin depths obtained from the intersections of the same temperaturecurves in FIG. 166 were input into equations based on theory and the ACresistance per unit length was calculated. The total AC resistance ofthe entire heater, including that of the canister, was subsequentlycalculated. A comparison between the experimental and numerical(calculated) results is shown in FIG. 167 for currents of 300 A(experimental data 1164 and numerical curve 1166), 400A (experimentaldata 1168 and numerical curve 1170), and 500 A (experimental data 1172and numerical curve 1174). Though the numerical results exhibit asteeper trend than the experimental results, the theoretical modelcaptures the close bunching of the experimental data, and the overallvalues are quite reasonable given the assumptions involved in thetheoretical model. For example, one assumption involved the use of apermeability derived from a quasistatic B-H curve to treat a dynamicsystem.

One feature of the theoretical model describing the flow of alternatingcurrent in the three-part temperature limited heater is that the ACresistance does not fall off monotonically with increasing skin depth.FIG. 168 shows the AC resistance (mΩ) per foot of the heater element asa function of skin depth (in.) at 1100° F. calculated from thetheoretical model. The AC resistance may be maximized by selecting theskin depth that is at the peak of the non-monotonical portion of theresistance versus skin depth profile (for example, at about 0.23 in. inFIG. 168).

FIG. 169 shows the power generated per unit length (W/ft) in each heatercomponent (curve 1176 (copper core), curve 1178 (carbon steel), curve1180 (347H outer layer), and curve 1182 (total)) versus skin depth(in.). As expected, the power dissipation in the 347H falls off whilethe power dissipation in the copper core increases as the skin depthincreases. The maximum power dissipation in the carbon steel occurs atthe skin depth of about 0.23 inches and is expected to correspond to theminimum in the power factor, as shown in FIG. 163. The current densityin the carbon steel behaves like a damped wave of wavelength λ=2πδ andthe effect of this wavelength on the boundary conditions at thecopper/carbon steel and carbon steel/347H interface may be behind thestructure in FIG. 168. For example, the local minimum in AC resistanceis close to the value at which the thickness of the carbon steel layercorresponds to λ/4. Formulae may be developed that describe the shapesof the AC resistance versus temperature profiles of temperature limitedheaters for use in simulating the performance of the heaters in aparticular embodiment. The data in FIGS. 161 and 162 show that theresistances initially rise linearly, then drop off increasingly'steeplytowards the DC lines.

FIGS. 170 A-C compare the results of the theoretical calculations withexperimental data at 300A (FIG. 170A), 400 A (FIG. 170B) and 500 A (FIG.170C). FIG. 170A depicts electrical resistance (mΩ) versus temperature(° F.) at 300 A. Data 1184 is the experimental data at 300 A. Curve 1186is the theoretical calculation at 300 A. Curve 1188 is a plot ofresistance versus temperature at 10 A DC. FIG. 170B depicts electricalresistance (mΩ) versus temperature (° F.) at 400 A. Data 1190 is theexperimental data at 400 A. Curve 1192 is the theoretical calculation at400 A. Curve 1194 is a plot of resistance versus temperature at 10 A DC.FIG. 170C depicts electrical resistance (mΩ) versus temperature (° F.)at 500 A. Data 1196 is the experimental data at 500 A. Curve 1198 is thetheoretical calculation at 500 A. Curve 1200 is a plot of resistanceversus temperature at 10 A DC.

Temperature Limited Heater Simulations

A numerical simulation (FLUENT available from Fluent USA, Lebanon, N.H.,U.S.A.) was used to compare operation of temperature limited heaterswith three turndown ratios. The simulation was done for heaters in anoil shale formation (Green River oil shale). Simulation conditions were:

-   -   61 m length conductor-in-conduit temperature limited heaters        (center conductor (2.54 cm diameter), conduit outer diameter 7.3        cm)    -   downhole heater test field richness profile for an oil shale        formation    -   16.5 cm (6.5 inch) diameter wellbores at 9.14 m spacing between        wellbores on triangular spacing    -   200 hours power ramp-up time to 820 watts/m initial heat        injection rate    -   constant current operation after ramp up    -   Curie temperature of 720.6° C. for heater    -   formation will swell and touch the heater canisters for oil        shale richnesses at least 0.14 L/kg (35 gals/ton)

FIG. 171 displays temperature (° C.) of a center conductor of aconductor-in-conduit heater as a function of formation depth (m) for atemperature limited heater with a turndown ratio of 2:1. Curves1202-1224 depict temperature profiles in the formation at various timesranging from 8 days after the start of heating to 675 days after thestart of heating (1202: 8 days, 1204: 50 days, 1206: 91 days, 1208: 133days, 1210: 216 days, 1212: 300 days, 1214: 383 days, 1216: 466 days,1218: 550 days, 1220: 591 days, 1222: 633 days, 1224: 675 days). At aturndown ratio of 2:1, the Curie temperature of 720.6° C. was exceededafter 466 days in the richest oil shale layers. FIG. 172 shows thecorresponding heater heat flux (W/m) through the formation for aturndown ratio of 2:1 along with the oil shale richness (1/kg) profile(curve 1226). Curves 1228-1260 show the heat flux profiles at varioustimes from 8 days after the start of heating to 633 days after the startof heating (1228: 8 days; 1230: 50 days; 1232: 91 days; 1234: 133 days;1238: 175 days; 1240: 216 days; 1242: 258 days; 1244: 300 days; 1236:341 days; 1246: 383 days; 1248: 425 days; 1250: 466 days; 1252: 508 days1254: 550 days; 1256: 591 days; 1258: 633 days; 1260: 675 days). At aturndown ratio of 2:1, the center conductor temperature exceeded theCurie temperature in the richest oil shale layers.

FIG. 173 displays heater temperature (° C.) as a function of formationdepth (m) for a turndown ratio of 3:1. Curves 1262-1284 show temperatureprofiles through the formation at various times ranging from 12 daysafter the start of heating to 703 days after the start of heating (1262:12 days; 1264: 33 days; 1266: 62 days; 1268: 102 days; 1270: 146 days;1272: 205 days; 1274: 271 days; 1276: 354 days; 1278: 467 days; 1280:605 days; 1282: 662 days; 1284: 703 days). At a turndown ratio of 3:1,the Curie temperature was approached after 703 days. FIG. 174 shows thecorresponding heater heat flux (W/m) through the formation for aturndown ratio of 3:1 along with the oil shale richness (1/kg) profile(curve 1286). Curves 1288-1308 show the heat flux profiles at varioustimes from 12 days after the start of heating to 605 days after thestart of heating (1288: 12 days, 1290: 32 days, 1292: 62 days, 1294: 102days, 1296: 146 days, 1298: 205 days, 1300: 271 days, 1302: 354 days,1304: 467 days, 1306: 605 days, 1308: 749 days). The center conductortemperature never exceeded the Curie temperature for the turndown ratioof 3:1. The center conductor temperature also showed a relatively flattemperature profile for the 3:1 turndown ratio.

FIG. 175 shows heater temperature (° C.) as a function of formationdepth (m) for a turndown ratio of 4:1. Curves 1310-1330 show temperatureprofiles through the formation at various times ranging from 12 daysafter the start of heating to 467 days after the start of heating (1310:12 days; 1312: 33 days; 1314: 62 days; 1316: 102 days, 1318: 147 days;1320: 205 days; 1322: 272 days; 1324: 354 days; 1326: 467 days; 1328:606 days, 1330: 678 days). At a turndown ratio of 4:1, the Curietemperature was not exceeded even after 678 days. The center conductortemperature never exceeded the Curie temperature for the turndown ratioof 4:1. The center conductor showed a temperature profile for the 4:1turndown ratio that was somewhat flatter than the temperature profilefor the 3:1 turndown ratio. These simulations show that the heatertemperature stays at or below the Curie temperature for a longer time athigher turndown ratios. For this oil shale richness profile, a turndownratio of at least 3:1 may be desirable.

Simulations have been performed to compare the use of temperaturelimited heaters and non-temperature limited heaters in an oil shaleformation. Simulation data was produced for conductor-in-conduit heatersplaced in 16.5 cm (6.5 inch) diameter wellbores with 12.2 m (40 feet)spacing between heaters using a formation simulator (for example, STARS)and a near wellbore simulator (for example, ABAQUS from ABAQUS, Inc.,Providence, R.I., U.S.A.). Standard conductor-in-conduit heatersincluded 304 stainless steel conductors and conduits. Temperaturelimited conductor-in-conduit heaters included a metal with a Curietemperature of 760° C. for conductors and conduits. Results from thesimulations are depicted in FIGS. 176-178.

FIG. 176 depicts heater temperature (° C.) at the conductor of aconductor-in-conduit heater versus depth (m) of the heater in theformation for a simulation after 20,000 hours of operation. Heater powerwas set at 820 watts/meter until 760° C. was reached, and the power wasreduced to inhibit overheating. Curve 1332 depicts the conductortemperature for standard conductor-in-conduit heaters. Curve 1332 showsthat a large variance in conductor temperature and a significant numberof hot spots developed along the length of the conductor. Thetemperature of the conductor had a minimum value of 490° C. Curve 1334depicts conductor temperature for temperature limitedconductor-in-conduit heaters. As shown in FIG. 176, temperaturedistribution along the length of the conductor was more controlled forthe temperature limited heaters. In addition, the operating temperatureof the conductor was 730° C. for the temperature limited heaters. Thus,more heat input would be provided to the formation for a similar heaterpower using temperature limited heaters.

FIG. 177 depicts heater heat flux (W/m) versus time (yrs) for theheaters used in the simulation for heating oil shale. Curve 1336 depictsheat flux for standard conductor-in-conduit heaters. Curve 1338 depictsheat flux for temperature limited conductor-in-conduit heaters. As shownin FIG. 177, heat flux for the temperature limited heaters wasmaintained at a higher value for a longer period of time than heat fluxfor standard heaters. The higher heat flux may provide more uniform andfaster heating of the formation.

FIG. 178 depicts cumulative heat input (kJ/m)(kilojoules per meter)versus time (yrs) for the heaters used in the simulation for heating oilshale. Curve 1340 depicts cumulative heat input for standardconductor-in-conduit heaters. Curve 1342 depicts cumulative heat inputfor temperature limited conductor-in-conduit heaters. As shown in FIG.178, cumulative heat input for the temperature limited heaters increasedfaster than cumulative heat input for standard heaters. The fasteraccumulation of heat in the formation using temperature limited heatersmay decrease the time needed for retorting the formation. Onset ofretorting of the oil shale formation may begin around an averagecumulative heat input of 1.1×10⁸ kJ/meter. This value of cumulative heatinput is reached around 5 years for temperature limited heaters andbetween 9 and 10 years for standard heaters.

Triad Pattern Heater Simulation

FIG. 179 depicts cumulative gas production and cumulative oil productionversus time (years) found from a STARS simulation (Computer ModellingGroup, LTD., Calgary, Alberta, Canada) using the temperature limitedheaters and heater pattern depicted in FIGS. 65 and 67. Curve 1344depicts cumulative oil production (m³) for an initial water saturationof 15%. Curve 1346 depicts cumulative gas production (m³) for theinitial water saturation of 15%. Curve 1348 depicts cumulative oilproduction (m³) for an initial water saturation of 85%. Curve 1350depicts cumulative gas production (m³) for the initial water saturationof 85%. As shown by the small differences between curves 1344 and 1348for cumulative oil production and curves 1346 and 1350 for cumulativegas production, the initial water saturation does not substantiallyalter heating of the formation. As a result, the overall production ofhydrocarbons from the formation is also not substantially changed by theinitial water saturation. Using the temperature limited heaters inhibitsvariances in heating of the formation that otherwise may be caused bythe differences in the initial water saturation.

Phase Transformation and Curie Temperature Experimental Calculations

FIG. 180 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy TC3 (0.1%by weight carbon, 5% by weight cobalt, 12% by weight chromium, 0.5% byweight manganese, 0.5% by weight silicon). Curve 1352 depicts weightpercentage of the ferrite phase. Curve 1354 depicts weight percentage ofthe austenite phase. The arrow points to the Curie temperature of thealloy. As shown in FIG. 180, the phase transformation was close to theCurie temperature but did not overlap with the Curie temperature forthis alloy.

FIG. 181 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy FM-4(0.1% by weight carbon, 5% by weight cobalt, 0.5% by weight manganese,0.5% by weight silicon). Curve 1356 depicts weight percentage of theferrite phase. Curve 1358 depicts weight percentage of the austenitephase. The arrow points to the Curie temperature of the alloy. As shownin FIG. 181, the phase transformation broadened without chromium in thealloy and the phase transformation overlapped with the Curie temperaturefor this alloy.

FIG. 181 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperauture for iron alloy FM-4(0.1% by weight carbon, 5% by weight cobalt, 0.5% by weight manganese,0.5% by weight silicon). Curve 1356 depicts weight percentage of theferrite phase. Curve 1358 depicts weight percentage of the austenitephase. The arrow points to the Curie temperature of the alloy. As shownin FIG. 181, the phase transformation broadened without chromium in thealloy and the phase transformation overlapped with the Curie temperaturefor this alloy.

Calculations for the Curie temperature (T_(c)) and the phasetransformation behavior were done for various mixtures of cobalt,carbon, manganese, silicon, vanadium, and titanium using computationalthermodynamic software (ThermoCalc and JMatPro obtained from Thermo-CalcSoftware, Inc., (McMurray, Pa., U.S.A)) to predict the effect ofadditional elements on Curie Temperature (T_(c)) for selectedcompositions, the temperature (A₁) at which ferrite tranforms toparamagnetic austenite, and the phases present at those temperatures. Anequilibrium calculation temperature of 700° C. was used in allcalculations. As shown in TABLE 2, as the weight percentage of cobalt inthe composition increased, T_(c) and A₁ increased; however, T_(c)remained above A₁. An increase in the A₁ temperature may be predictedupon sufficient addition of carbide formers vanadium, titanium, niobium,tantalum, and tungsten. For example, about 0.5% by weight of carbideformers may be used in an alloy that includes about 0.1% by weight ofcarbon. Addition of carbide formers allows replacement of the Fe₃Ccarbide phase with a MC carbide phase. From the calculations, excessamounts of vanadium appeared to not have an impact on T_(c), whileexcess amounts of other carbide educed the T_(c).

TABLE 2 Composition (% by weight, Calculation Results balance being Fe)Phases Present Co C Mn Si V Ti T_(c) (EC) A₁ (EC) (~700EC) 0 0.1 0.5 0.50 0 758 716 ferrite + Fe₃C (FM2) 2 0.1 0.5 0.5 0 0 776 726 ferrite +Fe₃C (FM4) 5 0.1 0.5 0.5 0 0 803 740 ferrite + Fe₃C (FM6) 8 0.1 0.5 0.50 0 829 752 ferrite + Fe₃C (FM8) 5 0.1 0.5 0.5 0.2 0 803 740 ferrite +Fe₃C + VC 5 0.1 0.5 0.5 0.4 0 802 773 ferrite + Fe₃C + VC 5 0.1 0.5 0.50.5 0 802 830 ferrite + VC 5 0.1 0.5 0.5 0.6 0 802 855 ferrite + VC 50.1 0.5 0.5 0.8 0 803 880 ferrite + VC 5 0.1 0.5 0.5 1.0 0 805 896ferrite + VC 5 0.1 0.5 0.5 1.5 0 807 928 ferrite + VC 5 0.1 0.5 0.5 2.00 810 959 ferrite + VC 6 0.1 0.5 0.5 0.5 0 811 835 ferrite + VC 7 0.10.5 0.5 0.5 0 819 839 ferrite + VC 8 0.1 0.5 0.5 0.5 0 828 843 ferrite +VC 9 0.1 0.5 0.5 0.5 0 836 847 ferrite + VC 10 0.1 0.5 0.5 0.5 0 845 852ferrite + VC 11 0.1 0.5 0.5 0.5 0 853 856 ferrite + VC 12 0.1 0.5 0.50.5 0 861 859 ferrite + VC 10 0.1 0.5 0.5 1.0 0 847 907 ferrite + VC 110.1 0.5 0.5 1.0 0 855 909 ferrite + VC 12 0.1 0.5 0.5 1.0 0 863 911ferrite + VC 13 0.1 0.5 0.5 1.0 0 871 913 ferrite + VC 14 0.1 0.5 0.51.0 0 879 915 ferrite + VC 15 0.1 0.5 0.5 1.0 0 886 917 ferrite + VC 170.1 0.5 0.5 1.0 0 902 920 ferrite + VC 20 0.1 0.5 0.5 1.0 0 924 926ferrite + VC 5 0.1 0.5 0.5 0 0.2 802 738 ferrite + Fe₃C + TiC 5 0.1 0.50.5 0 0.3 802 738 ferrite + Fe₃C + TiC 5 0.1 0.5 0.5 0 0.4 802 867ferrite + TiC 5 0.1 0.5 0.5 0 0.45 802 896 ferrite + TiC 5 0.1 0.5 0.5 00.5 801 902 ferrite + TiC 5 0.1 0.5 0.5 0 1.0 795 934 ferrite + TiC 80.1 0.5 0.5 0 0.5 827 905 ferrite + TiC 10 0.1 0.5 0.5 0 0.5 844 908ferrite + TiC 11 0.1 0.5 0.5 0 0.5 852 909 ferrite + TiC 12 0.1 0.5 0.50 0.5 860 911 ferrite + TiC 13 0.1 0.5 0.5 0 0.5 868 912 ferrite + TiC14 0.1 0.5 0.5 0 0.5 876 914 ferrite + TiC 15 0.1 0.5 0.5 0 0.5 884 915ferrite + TiC 17 0.1 0.5 0.5 0 0.5 899 918 ferrite + TiC 18 0.1 0.5 0.50 0.5 907 920 ferrite + TiC 19 0.1 0.5 0.5 0 0.5 914 921 ferrite + TiC20 0.1 0.5 0.5 0 0.5 922 923 ferrite + TiC 21 0.1 0.5 0.5 0 0.5 929 924ferrite + TiC 21 0.1 0.5 0.5 0 0.6 928 926 ferrite + TiC 21 0.1 0.5 0.50 0.7 926 928 ferrite + TiC 21 0.1 0.5 0.5 0 0.8 925 930 ferrite + TiC21 0.1 0.5 0.5 0 1.0 922 934 ferrite + TiC 22 0.1 0.5 0.5 0 1.0 930 935ferrite + TiC 23 0.1 0.5 0.5 0 1.0 937 936 ferrite + TiC

Several iron-cobalt alloys were prepared and their compositions aregiven in TABLE 3. These cast alloys were processed into rod and wire,and the measured and calculated T_(c) for the rods is listed. Averagesof cooling and heating T_(c) measurements were used since noirreversible hysteresis effect was observed during heating and cooling.As shown in TABLE 3, the agreement between calculated T_(c) and themeasured T_(c) was acceptable.

The measured T_(c) were performed by inserting rods into a furnace andthe T_(c) temperature was measured during heating. A thermocouple wasattached midway along the length. The torus technique involves winding atorus with the sample material.

TABLE 3 Nominal Composition (% by weight, T_(c) (EC) T_(c) (EC) Alloybalance being Fe) (torus (rod, T_(c) (EC) Designation Co C Mn Sitechnique) uncorrected) (calculated) FM1 0 0 0 0 768 — 770 FM2 0 0.1 0.50.5 — 751 758 FM3 5 0 0 0 — — 818 FM4 5 0.1 0.5 0.5 — 821 803 FM5 8 0 00 — — 842 FM6 8 0.1 0.5 0.5 — 858 826 FM7 10 0 0 0 863 886 859 FM8 100.1 0.5 0.5 — 874 846

FIG. 182 depicts the Curie temperature (solid horizontal bars) and phasetransformation temperature range (slashed vertical bars) for severaliron alloys. Column 1360 is for FM-2 iron-cobalt alloy. Column 1362 isfor FM-4 iron-colbalt alloy. Column 1364 is for FM-6 iron-cobalt alloy.Column 1366 is for FM-8 iron-cobalt alloy. Column 1368 is for TC1 410stainless steel alloy with cobalt. Column 1370 is for TC2 410 stainlesssteel alloy with cobalt. Column 1372 is for TC3 410 stainless steelalloy with cobalt. Column 1374 is for TC4 410 stainless steel alloy withcobalt. Column 1376 is for TC5 410 stainless steel alloy with cobalt. Asshown in FIG. 182, the iron-cobalt alloys (FM-2, FM-6, FM-8) had largephase transformation temperature ranges that overlap with the Curietemperature. The 410 stainless steel alloys with cobalt (TC1, TC2, TC3,TC4, TC5) had small phase transformation temperature ranges. The phasetransformation temperature ranges for TC1, TC2, and TC3 were above theCurie temperature. The phase transformation temperature range for TC4was below the Curie temperature. Thus, a temperature limited heaterusing TC4 may self-limit at a temperature below the Curie temperature ofthe TC4.

FIGS. 183-186 depict the effects of alloy addition to iron-cobaltalloys. FIGS. 183 and 184 depict the effects of carbon addition to aniron-cobalt alloy. FIGS. 185 and 186 depict the effects of titaniumaddition to an iron-cobalt alloy.

FIG. 183 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt and 0.4% by weight manganese. Curve 1378depicts weight percentage of the ferrite phase. Curve 1380 depictsweight percentage of the austenite phase. The arrow points to the Curietemperature of the alloy. As shown in FIG. 183, the phase transformationwas close to the Curie temperature but did not overlap with the Curietemperature for this alloy.

FIG. 184 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.01% carbon.Curve 1382 depicts weight percentage of the ferrite phase. Curve 1384depicts weight percentage of the austenite phase. The arrow points tothe Curie temperature of the alloy. As shown in FIGS. 183 and 184, thephase transformation broadened with the addition of carbon to the alloywith the onset of the phase transformation shifting to a lowertemperature. Thus, carbon may be added to an iron alloy to lower theonset temperature and broaden the temperature range of the phasetransformation.

FIG. 185 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.085%carbon. Curve 1386 depicts weight percentage of the ferrite phase. Curve1388 depicts weight percentage of the austenite phase. The arrow pointsto the Curie temperature of the alloy. As shown in FIG. 185, the phasetransformation overlapped with the Curie temperature.

FIG. 186 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, 0.085% carbon,and 0.4% titanium. Curve 1390 depicts weight percentage of the ferritephase. Curve 1392 depicts weight percentage of the austenite phase. Thearrow points to the Curie temperature of the alloy. As shown in FIGS.185 and 186, the phase transformation narrowed with the addition oftitanium to the alloy with the onset of the phase transformationshifting to a higher temperature. Thus, titanium may be added to an ironalloy to raise the onset temperature and narrow the temperature range ofthe phase transformation.

FIG. 187 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for 410 stainless steeltype alloy (12% by weight chromium, 0.1% by weight carbon, 0.5% byweight manganese, 0.5% by weight silicon, with the balance being iron).Curve 1394 depicts weight percentage of the ferrite phase. Curve 1396depicts weight percentage of the austenite phase. The arrow points tothe Curie temperature of the alloy. As shown in FIG. 187, the phasetransformation broadened without chromium in the alloy and the phasetransformation overlaps with the Curie temperature for this alloy.

Calculations for the Curie temperature and the phase transformationbehavior were done for various mixtures of cobalt, carbon, manganese,silicon, vanadium, and titanium using the computational thermodynamicsoftware (ThermoCalc and JmatPro) to predict the effect of additionalelements on Curie Temperature (T_(c)) for selected compositions and thetemperature (A₁) at which ferrite transforms to paramagnetic austenite.An equilibrium calculation temperature of 700° C. was used in allcalculations. As shown in TABLE 4, as the weight percentage of cobalt inthe composition incresased, T_(c) and A₁ decreased. As shown in TABLE 4,addition of vanadium and/or titanium increased A₁. The addition ofvanadium may allow increased amounts of chromium to be used in Curieheaters.

TABLE 4 Composition (% by weight, Calculation balance being Fe) ResultsCo Cr C Mn Si V Ti T_(c) (EC) A₁ (EC) 0 12 0.1 0.5 0.5 0 0 723 814 2 120.1 0.5 0.5 0 0 739 800 4 12 0.1 0.5 0.5 0 0 754 788 6 12 0.1 0.5 0.5 00 769 780 8 12 0.1 0.5 0.5 0 0 783 773 10 12 0.1 0.5 0.5 0 0 797 766 012 0.1 0.5 0.5 1 0 726 2 12 0.1 0.5 0.5 1 0 741 4 12 0.1 0.5 0.5 1 0 7566 12 0.1 0.5 0.5 1 0 770 8 12 0.1 0.5 0.5 1 0 784 794 10 12 0.1 0.5 0.51 0 797 0 12 0.1 0.5 0.5 2 0 726 2 12 0.1 0.5 0.5 2 0 742 6 12 0.1 0.50.5 2 0 772 8 12 0.1 0.5 0.5 2 0 785 817 10 12 0.1 0.5 0.5 2 0 797 0 120.1 0.5 0.5 0 0.5 718 863 2 12 0.1 0.5 0.5 0 0.5 733 825 4 12 0.1 0.50.5 0 0.5 747 803 6 12 0.1 0.5 0.5 0 0.5 761 787 8 12 0.1 0.5 0.5 0 0.5775 775 10 12 0.1 0.5 0.5 0 0.5 788 767 0 12 0.1 0.5 0.5 1 0.5 721 2 120.1 0.5 0.5 1 0.5 736 4 12 0.1 0.5 0.5 1 0.5 750 6 12 0.1 0.5 0.5 1 0.5763 8 12 0.1 0.5 0.5 1 0.5 776 10 12 0.1 0.5 0.5 1 0.5 788 0 12 0.1 0.50.5 2 0.5 725 2 12 0.1 0.5 0.5 2 0.5 738 4 12 0.1 0.5 0.5 2 0.5 752 6 120.1 0.5 0.5 2 0.5 764 8 12 0.1 0.5 0.5 2 0.5 777 10 12 0.1 0.5 0.5 2 0.5788 0 12 0.1 0.5 0.5 0 1 712 >1000 2 12 0.1 0.5 0.5 0 1 727 877 4 12 0.10.5 0.5 0 1 741 836 6 12 0.1 0.5 0.5 0 1 755 810 8 12 0.1 0.5 0.5 0 1768 794 10 12 0.1 0.5 0.5 0 1 781 780 0 12 0.1 0.5 0.5 1 1 715 2 12 0.10.5 0.5 1 1 730 4 12 0.1 0.5 0.5 1 1 743 6 12 0.1 0.5 0.5 1 1 757 8 120.1 0.5 0.5 1 1 770 821 10 12 0.1 0.5 0.5 1 1 782 0 12 0.1 0.5 0.5 2 1718 2 12 0.1 0.5 0.5 2 1 732 4 12 0.1 0.5 0.5 2 1 745 6 12 0.1 0.5 0.5 21 758 8 12 0.1 0.5 0.5 2 1 770 873 10 12 0.1 0.5 0.5 2 1 782 0 12 0.10.3 0.5 0 0 727 826 2 12 0.1 0.3 0.5 0 0 742 810 4 12 0.1 0.3 0.5 0 0758 800 6 12 0.1 0.3 0.5 0 0 772 791 8 12 0.1 0.3 0.5 0 0 786 784 10 120.1 0.3 0.5 0 0 800 777 0 12 0.1 0.3 0.5 1 0 730 2 12 0.1 0.3 0.5 1 0745 4 12 0.1 0.3 0.5 1 0 760 6 12 0.1 0.3 0.5 1 0 774 8 12 0.1 0.3 0.5 10 787 10 12 0.1 0.3 0.5 1 0 801 0 12 0.1 0.3 0.5 2 0 730 2 12 0.1 0.30.5 2 0 746 4 12 0.1 0.3 0.5 2 0 762 6 12 0.1 0.3 0.5 2 0 775 8 12 0.10.3 0.5 2 0 788 10 12 0.1 0.3 0.5 2 0 801 0 12 0.1 0.3 0.5 0 0.5 722 212 0.1 0.3 0.5 0 0.5 737 4 12 0.1 0.3 0.5 0 0.5 751 6 12 0.1 0.3 0.5 00.5 765 8 12 0.1 0.3 0.5 0 0.5 779 10 12 0.1 0.3 0.5 0 0.5 792 0 12 0.10.3 0.5 1 0.5 725 2 12 0.1 0.3 0.5 1 0.5 740 4 12 0.1 0.3 0.5 1 0.5 7536 12 0.1 0.3 0.5 1 0.5 767 8 12 0.1 0.3 0.5 1 0.5 780 10 12 0.1 0.3 0.51 0.5 792 0 12 0.1 0.3 0.5 2 0.5 728 2 12 0.1 0.3 0.5 2 0.5 742 4 12 0.10.3 0.5 2 0.5 755 6 12 0.1 0.3 0.5 2 0.5 768 8 12 0.1 0.3 0.5 2 0.5 78010 12 0.1 0.3 0.5 2 0.5 792 0 12 0.1 0.3 0.5 0 1 715 2 12 0.1 0.3 0.5 01 730 4 12 0.1 0.3 0.5 0 1 745 6 12 0.1 0.3 0.5 0 1 759 8 12 0.1 0.3 0.50 1 772 10 12 0.1 0.3 0.5 0 1 785 0 12 0.1 0.3 0.5 1 1 719 2 12 0.1 0.30.5 1 1 733 4 12 0.1 0.3 0.5 1 1 747 6 12 0.1 0.3 0.5 1 1 760 8 12 0.10.3 0.5 1 1 773 834 10 12 0.1 0.3 0.5 1 1 786 0 12 0.1 0.3 0.5 2 1 722 212 0.1 0.3 0.5 2 1 736 4 12 0.1 0.3 0.5 2 1 749 6 12 0.1 0.3 0.5 2 1 7628 12 0.1 0.3 0.5 2 1 774 886 10 12 0.1 0.3 0.5 2 1 786 7.5 12.25 0.1 0.30.5 0 0 781 785 8.0 12.25 0.1 0.3 0.5 0 0 785 783 8.5 12.25 0.1 0.3 0.50 0 788 781 9.0 12.25 0.1 0.3 0.5 0 0 792 779 9.5 12.25 0.1 0.3 0.5 0 0795 778 10.0 12.25 0.1 0.3 0.5 0 0 798 776 6.0 12.25 0.1 0.5 0.5 0 0 767780 6.5 12.25 0.1 0.5 0.5 0 0 771 778 7.0 12.25 0.1 0.5 0.5 0 0 774 7767.5 12.25 0.1 0.5 0.5 0 0 778 774 7.5 12.25 0.1 0.3 0.5 1 0 782 812 8.012.25 0.1 0.3 0.5 1 0 786 809 8.5 12.25 0.1 0.3 0.5 1 0 789 806 9.012.25 0.1 0.3 0.5 1 0 792 804 9.5 12.25 0.1 0.3 0.5 1 0 795 801 10.012.25 0.1 0.3 0.5 1 0 799 799 7.5 12.25 0.1 0.5 0.5 1 0 779 801 8.012.25 0.1 0.5 0.5 1 0 782 799 8.5 12.25 0.1 0.5 0.5 1 0 785 796 9.012.25 0.1 0.5 0.5 1 0 788 793 9.5 12.25 0.1 0.5 0.5 1 0 792 791 10.012.25 0.1 0.5 0.5 1 0 795 788 7.5 12.25 0.1 0.3 0.5 0 0.5 774 788 8.012.25 0.1 0.3 0.5 0 0.5 777 785 8.5 12.25 0.1 0.3 0.5 0 0.5 781 782 9.012.25 0.1 0.3 0.5 0 0.5 784 780 7.5 12.25 0.1 0.5 0.5 0 0.5 770 777 8.012.25 0.1 0.5 0.5 0 0.5 774 774 8.5 12.25 0.1 0.5 0.5 0 0.5 777 771 7.512.25 0.1 0.3 0.5 1 0.5 775 823 8.0 12.25 0.1 0.3 0.5 1 0.5 778 819 8.512.25 0.1 0.3 0.5 1 0.5 782 814 9.0 12.25 0.1 0.3 0.5 1 0.5 785 810 9.512.25 0.1 0.3 0.5 1 0.5 788 807 10.0 12.25 0.1 0.3 0.5 1 0.5 791 80310.5 12.25 0.1 0.3 0.5 1 0.5 794 800 11.0 12.25 0.1 0.3 0.5 1 0.5 797797 7.5 12.25 0.1 0.5 0.5 1 0.5 771 811 8.0 12.25 0.1 0.5 0.5 1 0.5 775807 8.5 12.25 0.1 0.5 0.5 1 0.5 778 803 9.0 12.25 0.1 0.5 0.5 1 0.5 781799 9.5 12.25 0.1 0.5 0.5 1 0.5 784 796 10.0 12.25 0.1 0.5 0.5 1 0.5 787792 10.5 12.25 0.1 0.5 0.5 1 0.5 790 789

Several iron-chromium alloys were prepared and their compositions aregiven in TABLE 5. These cast alloys were processed into rod and torus,and the calculated and measured T_(c) for the torus and rods is listed.

TABLE 5 T_(C) T_(C) (EC) T_(C) T_(C) A₁ Alloy Actual Composition (% byweight, balance Fe) (EC) (rod, (EC) (EC) (EC) Designation Co Cr C Mn SiV Ti (torus) uncorrected) (calorimetry) (calculated) (calculated)  TC1b0.02 13.2 0.08 0.45 0.69 0 0.01 692 — — 717 819 TC2 2.44 12.3 0.10 0.480.47 0 0.01 — 745 — 742 793 TC3 4.81 12.3 0.10 0.48 0.46 0 0.01 — 758 —761 783 TC4 9.75 12.2 0.07 0.49 0.47 0 0.01 759/ 770/ — 793 765 682*684* TC5 9.80 12.2 0.10 0.48 0.46 1.02 0.01 — 784/ — 795 790 690* TC67.32 12.3 0.12 0.29 0.46 0.89 0.46 754 — 752 775 813 TC7 7.46 12.1 0.110.27 0.46 0.92 0 747 — 757 785 811 TC8 7.49 12.1 0.11 0.28 0.45 0 0 761— 774 784 786 *Two values represent T_(C) during heating and T_(C)during subsequent cooling.Modeling of Alloy Phase Behavior

Modeling of phase behavior for different improved alloy compositions todetermine compositions that contain increased amounts of phases thatcontribute positively to physical properties was performed. Compositionssuch as Cu, Z, M(C,N), M₂(C,N), and M₂₃C₆, and may minimize the amountof phases that are embritting phases such as G, sigma, laves, and chi.There may be other reasons to include certain components. For example,silicon, is typically included in stainless steel alloys to improveprocessing properties, and nickel and chromium are typically included inthe alloys to impart corrosion resistance. When two components may beincluded to accomplish the same result, then the less expensivecomponent may be beneficially included. For example, to the extentmanganese may be substituted for nickel without sacrificing performance,such a substitution may reduce the cost of the alloy at currentcomponent prices.

The effect of total phase content of the alloys similar to thosedescribed above has been found to be approximated by the equation:σ_(r)=1.0235(TPC)+5.5603  (10)

Where σ_(r) is the creep rupture strength for one thousand hours at 800°C. in (kilo-pound per square inch (ksi) and TPC is the total phasecontent calculated for the composition. This estimate was furtherimproved by only including in the TPC term the amount of Cu phase, Zphase, M(C,N) phase, M₂(C,N) phase, and M_(23C) ₆ phase (the “desirablephases”), and calculating the constants on this basis. Anotherimprovement to this estimate may be to use only the difference betweenthe desirable phases present at the annealing temperature and at 800° C.Thus, the components that do not go into solution in the annealingprocess were not considered because they do not add significantly to thestrength of the alloys at elevated temperatures. For example, thedifference between the amount of Cu phase, Z phase, M(C,N) phase,M₂(C,N) phase, and M₂₃C₆ phase present based on equilibrium calculationsat annealing temperatures less the amount calculated to be present at800° C. may be about 1% by weight of the alloy, or it could be about1.5% by weight of the alloy or about 2% by weight of the alloy, toresult in an alloy with good high temperature strength. Further, theannealing temperature may be about 1200° C., or it may be about 1250°C., or it may be about 1300° C.

The improved alloys of the present invention may be further understoodby modeling the addition, or reduction, of different metals to determinethe effect of changing amounts of that metal on the phase content of thealloy. For example, with a starting composition by weight of: 20% Cr, 3%Cu, 4% Mn, 0.3% Mo, 0.8% Nb, 12.5% Ni, 0.5% Si, 1% W, 0.1% C and 0.25%N, modeling with varying amounts of Cr results in included phases ofM₂₃C₆, M(C,N), M₂(C,N), Z, Cu, chi, laves, G, and sigma at 800° C.,according to FIG. 188. The amount of these phases plotted in each ofFIGS. 188-198 is the calculated amount of these phases at 800° C. InFIGS. 188-198, curve 1398 refers to M₂₃C₆, curve 1400 refers to M₂(C,N)phase, curve 1402 refers to Z phase, curve 1404 refers to Cu phase,curve 1406 refers to sigma phase, curve 1408 refers to chi phase, curve1410 refers to G phase, curve 1412 refers to laves phase, and curve 1414refers to M(C,N) phase.

FIG. 188 depicts the weight percentages of phases verus weigh percentageof chromium (Cr) in the alloy. As shown, the weight percentages ofphases 1398, 1400, 1402, and 1404 remained relatively constant fromabout 20% by weight to about 30% by weight of chromium, while sigmaphase 1406 increased linearly above a chromium content of about 20.5% byweight. Thus, from the modeling, a chromium content between about 20% byweight and about 20.5% by weight of the alloy may be favorable.

FIG. 189 depicts weight percentages of phases verus the weightpercentage of silicon (Si) in the alloy. As shown in IG. 189, varyingthe silicon content of the alloy resulted in sigma phase 1406 appearingat levels above about 1.2% by weight silicon and chi phase 1408appearing above a content of about 1.4% by weight silicon. G phase 1410appeared above about 1.6% by weight silicon and increased as the weightpercent of silicon increased. With increasing weight percentages ofsilicon, phases 1398, 1400, and 1402, remained relatively constant and aslight increase in Cu phase 1404 was predicted. The appearance of sigmaphase 1406, chi phase 1408 and G phase 1410 indicates that a siliconcontent below about 1.2% by weight in this alloy may be favorable.

FIG. 190 depicts weight percentage of phases formed verus weightpercentage of tungsten (W) in the alloy. As shown in FIG. 190, varyingthe weight percentage of tungsten (W) in the alloy resulted in sigmaphase 1406 appearing at about 1.4% by weight tungsten. Laves phase 1412appeared at about 1.5% by weight tungsten and increased with increasingweight percentage of tungsten. Thus, the model predicts a tungstencontent in this alloy of below about 1.3% by weight may be favorable.

FIG. 191 depicts weight percentage of phases formed versue the weightpercentage of niobium (Nb) in the alloy. As shown in FIG. 191, modelingpredicted that weight percentage of Z phase 1402 increased in a linearfashion as the weight percentage of niobium (Nb) increased in the alloyuntil the niobium content of the alloy reached about 1.55% by weight. Asthe niobium content increased from about 0.1% by weight to about 1.4% byweight, M₂(C,N) phase 1400 decreased fairly linearly. The decrease inM₂(C,N) phase 1400 was compensated for by the increase in Z phase 1402,and Cu phase 1404 and M₂₃C₆ phase 1398. Above about 1.5% by weightniobium in the alloy, sigma phase 1406 increased rapidly, Z phase 1402decreased, M₂₃C₆ phase 1398 decreased, and M(C,N) phase 1414 appeared.Thus, the niobium content in the alloy of at most 1.5% by weight maymaximize the weight percent of phases 1398, 1400, 1402, and 1404 andavoid minimizing the weight percent of sigma phase 1406 formed in thealloy. In order to make the alloy hot-workable, it was found that atleast about 0.5% by weight of niobium was desirable. Thus, in someembodiments, the alloy contains from about 0.5% by weight to about 1.5%by weight, or from about 0.8% by weight to about 1% by weight niobium.

FIG. 192 depicts weight perctanges of phases formed verus weightpercentage of carbon (C). As shown in FIG. 192, weight percentage ofsigma phase 1406 was predicted to decrease as the weight percentage ofcarbon in the alloy increased from about 0 to about 0.06. The weightpercentage of M₂₃C₆ phase 1398 was predicted to increase linearly as theweight percentage of carbon in the alloy increased to at most 0.5.M₂(C,N) phase 1400, Z phase 1402, and Cu phase 1404 was predicted toremain relatively constant as the weight percentage of carbon increasedin the alloy. Since, sigma phase 1406 decreased after about 0.06% byweight carbon, a carbon content of about 0.06% by weight to about 0.2%weight in the alloy may be beneficial.

FIG. 193 depicts weight percentage of phases formed verus weightpercentage of nitrogen (N). As shown in FIG. 193, the content ofnitrogen in the alloy increased from about 0% by weight to about 0.15%by weight, a content of sigma phase 1406 decreased from about 7% byweight to about 0% by weight, a content of M(C,N) phase 1414 decreasedfrom about 1% by weight to about 0% by weight, a content of M₂₃C₆ phase1398 increased from about 0% by weight to about 1.9% by weight, and acontent of Z phase 1402 increased from about 0% by weight to about 1.4%by weight. Above a nitrogen content of 0.15% by weight in the alloy,M₂(C,N) phase 1400 appeared and increaseed with as the content ofnitrogen in the alloy increases. Thus, a nitrogen content in a range ofabout 0.15% to about 0.5% by weight in the alloy may be beneficial.

FIG. 194 depicts weight percentage of phases formed verus weightpercentage of titanium (Ti). As shown in FIG. 194, varying the weightpercentage of titanium from 0.19 to about 1 may contribute to anincrease in a weight percentage of sigma phase 1406 from about 0 toabout 7.5 in the alloy. Thus, a titanium content of below about 0.2% byweight in the alloy may be desirable. As shown, as the content of Tiincreased from about 0% by weight to about 0.2% by weight, an increasein the weight percentage of M(C,N) phase 1414 occurred, a decrease inthe weight percentage of M₂(C,N) phase 1400 occurred, and a decrease inthe weight percentage Z phase 1402 occurred. The decreases in the amountof M₂(C,N) phase 1400 and Z phase 1402 appear to offset the increase inthe weight percent of M(C,N) phase 1414. Thus, inclusion of Ti in thealloy may be for purposes other than for increasing the amount of phasesthat improve properties of the alloy.

FIG. 195 depicts weight percentage of phases formed versus weightpercentage of copper (Cu). As shown in In FIG. 195, weight percentagesof M₂₃C₆ phase 1398, M₂(C,N) phase 1400, and Z phase 1402 did not varysign the weight percent of copper in the alloy increased. When thecontent of copper in the alloy increases above about 2.5% by weight, Cuphase 1404 increased significantly. Thus, in some embodiments, it isdesirable to have more than about 3% by weight copper in the alloy. Insome embodiments, about 10% by weight of copper in the alloy isbeneficial.

FIG. 196 depicts weight percentage of phases formed verus weightpercentage of manganese (Mn). As shown in FIG. 196, varying the contentof manganese in the alloy did not greatly affect the weight percentageof beneficial phases M₂₃C₆ phase 1398, M₂(C,N) phase 1400, Z phase 1402,and Cu phase 1404 in the alloy. The amount of manganese may therefore bevaried in order to reduce cost, or for other reasons, withoutsignificantly effecting the high temperature properties of the alloy,with an acceptable range of manganese content of the alloy being fromabout 2% by weight to about 10% by weight.

FIG. 197 depicts weight percentage of phases formed verus weightpercentage of nickel (Ni). As shown in FIG. 197, as the nickel contentof the alloy increased above about 8.4% by weight, a decrease in sigmaphase 1406 was observed. As the Ni content of the alloy was increasedfrom about 8% by weight to about 17% by weight, Cu phase 1404 decreasedalmost linearly until it disappeared at about 17% by weight and a smallincrease in the weight percentage of M₂(C,N) phase 1400 was predicted.From the model, a content of nickel of about 10% by weight to about 15%by weight in the alloy, or in other embodiments, a nickel content ofabout 12% by weight to about 13% by weight in the alloy may avoid theformation of sigma phase 1406, while improvements in corrosionproperties offset any detrimental effect of less Cu phase 1404.

FIG. 198 depicts weight percentage of phases formed verus weightpercentage of molybdenum (Mo). As shown in FIG. 198, the weightpercentage of beneficial phases M₂₃C₆ phase 1398, M₂(C,N) phase 1400, Zphase 1402, and Cu phase 1404 remained relatively constant as the weightpercentage of molybdenum in the alloy was varied. As Mo content of thealloy exceeded about 0.65% by weight, the weight percentages of sigmaphase 1406 and chi phase 1408 in the alloy increased significantly withno significant changes in the other phases. The content of molybdenum inthe alloy, in some embodiments, may therefore be limited to at mostabout 0.5% by weight.

Alloy Examples

Alloys A through N were prepared according to TABLE 6. Measuredcompositions are included in the table when such measurements areavailable. The total phase content of the alloys are calculated for thecomposition listed.

TABLE 6 % by weight 800° C. Total Alloy Cr Cu Mn Mo Nb Ni Si W C N₂ TiPhase A Target 20 — 4 0.3 0.8 12.5 0.5 — 0.09 0.25 — Actual^(b) 19 — 4.20.3 0.8 12.5 0.5 — 0.09 0.24 — 3.35^(a) B Target 20 3 4 0.3 0.8 13 0.5 10.09 0.25 — Actual-1^(b) 20 3 4 0.3 0.77 13 0.5 1 0.09 0.26 — 4.40^(a)Actual-2^(b) 20.35 2.94 4.09 0.28 0.76 12.52 0.44 1.03 0.09 0.23 —Actual-3^(b,c) 18.78 2.94 2.85 0.29 0.65 12.75 0.39 1.03 0.10 0.23 0.004C Target 20 4.5 4 0.3 0.8 12.5 0.5 1 0.15 0.25 — 7.15 Actual-1^(b) 18.744.37 3.68 0.29 0.77 13.00 0.43 1.18 0.11 0.17 0.002 5.45 Actual-2^(c,b)20.48 4.75 4.13 0.30 0.07 12.81 0.52 1.18 0.17 0.14 0.01 6.23 D Target20 4.5 4 0.3 0 12.5 0.5 1 0.2 0.5 0 10 E Target 20 4 4 0.5 0.8 12.5 0.51 0.1 0.3 — 6.2 Actual 18.84 4.34 3.65 0.29 0.75 12.93 0.43 1.21 0.090.2 0.002 5.3 F Target 20 3 1 0.3 0.77 13 0.5 1 0.09 0.26 — 4.7Actual^(b) 18.97 2.88 0.92 0.29 0.74 13.25 0.43 1.17 0.05 0.12 <0.0012.45 G Target 20 4.5 4 0.3 0.8 7 0.5 1 0.2 0.5 — Actual^(e) 20.08 4.36 40.3 0.81 7.01 0.5 1.04 0.24 0.31 0.008 9.6^(a) H Target 21 3 3 0.3 0.807 1 2 0.1 0.4 — Actual^(e) 21.1 2.95 3.01 0.31 0.82 6.98 0.51 2.06 0.130.32 <0.001 13.46^(f) I Target 21 3 8 0.3 0.80 7 0.5 1 0.1 0.5 — 7.1Actual^(e) 21.31 2.94 7.95 0.31 0.83 7.02 0.52 1.05 0.13 0.37 0.003 9.45J Target 20 4 2 0.5 1.00 12.5 1 1 0.20 0.50 — 9.8 Actual^(e) 19.93 3.852.13 0.5 0.99 12.11 1.08 1.01 0.23 0.29 0.022 8.95 K Target 20 3 4 0.30.77 13 0.5 1 0.09 0.26 — Actual^(e) 18.94 2.96 4.01 0.31 0.81 13.050.52 1.03 0.12 0.35 0.018 5.62 L Target 20 3 4 0.3 0.10 13 0.5 1 0.090.26 — Actual^(b) 20.06 2.96 3.95 0.3 0.12 12.93 0.59 1.03 0.11 0.250.005 4.28 M Target 20 3 4 0.3 0.50 13 0.5 1 0.09 0.26 — Actual^(b)20.11 2.93 3.98 0.3 0.51 12.94 0.5 1.03 0.12 0.13 <0.001 2.76 N Target20 3.4 4 1 0.80 12.5 0.5 2 0.1 0.3 8.85^(g) ^(a)Calculated using actualcomposition; ^(b)Nonconsumable-arc melted; ^(c)Remelted by elementcompensation; ^(d)Contains 1.7% sigma phase and 1.55% laves phase;^(e)Induction melted; ^(f)Contains 3.9% sigma phase and 1.7% chi phase;^(g)Includes 1.7% sigma and 1.55% laves phases.Hot Working with Niobium Example

To determine the capability for alloys to be hot worked, samples ofalloys C, D, E, F, K and L in TABLE 6 were prepared by arc-melting onepound samples into ingots of about 25.4 millimeter×24.4 millimeter×101.6millimeter (1 inch×1 inch×4 inch). After cutting hot-tops and removingsome shrinkage underneath, each sample was homogenized at 1200° C. forone hour, and then hot-rolled to a thickness of about 12.7 millimeter(0.5 inch) at 1200° C. with intermediate heat. The samples were thencold rolled to a 6.34 millimeter (0.25 inch) thick plate and vacuumannealed at 1200° C. for one hour. The compositions of the samples areincluded in TABLE 7 below, with the balance of the compositions beingiron.

When alloy D was hot rolled, it cracked and the rolling to 12.7millimeter (0.5 inch) thickness could not be accomplished. Alloy L couldbe hot-rolled, but developed cracks from the edge of the samplesprogressing toward the center of the sample, and would not be a usefulmaterial after such hot rolling. The other samples were processed usingthe above described procedure without any problems, resulting in 6.35millimeter (0.25 inch) plates that were free of cracks. It has beenfound that even 0.07% by weight niboium in the alloy composition maysignificantly reduce the tendency of the alloy to develop cracks duringhot working, and about 0.5% by weight to about 1.2% by weight niobiumcan be incorporated in wrought alloys to improve properties such as hotworkability.

High Temperature Heat Treating Example

Samples of alloys A and B from TABLE 6 were processed by two differentmethods. Process A included a heat treating and an annealing step whichwere at 1200° C. Process B included a heat treating and an annealingstep which were at 1250° C. With the higher heat treating and annealingtemperatures, measurable improvements in yield strength and ultimatetensile strength were observed for the two alloys when processed at thehigher temperature.

The process with 1200° C. processing was accomplished as follows:sections of six inch ID by 1.5 inches thick centrifugally cast pipe werehomogenized at 1200° C. for one and a half hours; a section was thenhot-rolled at 1200° C. to a one inch thickness for alloy A and athree-quarter inch thickness for alloy B; after cooling to roomtemperature, the plates were given a fifteen minute anneal at 1200° C.;the plates were then cold-rolled to a thickness of 13.97 millimeter(0.55 inches); the cold-rolled plates were given an anneal for one hourat 1200° C. in air with an argon blanket; and the plates were then givena final anneal for one hour at 1250° C. in air with an argon blanket.This process is referred to herein as process A.

The process with higher heat treating and annealing temperatures variedfrom the above procedure by homogenization of the cast plates at 1250°C. for three hours instead of one and a half hours; hot rolling wascarried out at 1200° C. from a one and a 12.7 millimeter (0.5 inch)thickness to a 19.05 millimeter (0.75 inch) thickness; and the resultingplate was annealed for fifteen minute at 1200° C. followed bycold-rolling to 13.97 millimeter (0.55 inch) thickness. This process isreferred to herein as process B.

FIG. 199 depicts yield strengths and ultimate tensile strengths fordifferent metals. Data 1416 shows yield strength and data 1418 showsultimate tensile strength for alloy A treated by process A. Data 1420shows yield strength and data 1422 shows ultimate tensile strength foralloy B treated by process B. Data 1424 shows yield strength and data1426 shows ultimate tensile strength for 347H stainless steel. Bothultimate tensile strength and yield strength were greater for the alloystreated at higher temperatures as compared to 347H stainless steel. Aconsiderable improvement over 347H can be seen for alloys A and B. Forexample, alloy A and alloy B retained tensile properties to testtemperatures of about 1000° C. For an application where yield strengthof about 20 ksi was needed, alloy A and alloy B provide the needed yieldstrength for at least an additional about 250° C. For a 5 ksi differencebetween yield and ultimate tensile strength at test temperatures, alloyA and alloy B may be used at temperatures of about 950° C. and about1000° C. as opposed to only about 870° C. for 347H.

Samples of Alloy B, treated by process A and by process B were subjectedto stress-rupture tests and the results are tabulated in TABLE 7. It canbe seen from Table 7 that process B, with a higher annealingtemperature, resulted in about 47% to about 474% improvement in time torupture.

TABLE 7 Process A Process B Temperature life life Improvement by (C.)Stress(MPa) (hours) (hours) Process B 800 100 164.2 241.6 47% 850 70 32151.7 474%  850 55 264.1 500.7 90% 900 42 90.1 140.1 55%High Temperature Yield after Cold Work and Aging Example

A sample of alloy B, processed by process B, was aged at 750° C. for1000 hours after being cold worked by 2.5%, 5%, and 10%, and withoutcold working. After aging, each was tested for tensile strength andyield strength at about 750° C. Results are tabulated in TABLE 8. It canbe seen from TABLE 8, that the yield strength increased significantly asa result of cold work and high temperature aging. The ultimate tensilestrength at about 750° C. decreased only slightly as a result of thehigh temperature aging and cold working. The annealed only sample andthe aged only sample were also tested at room temperature for yieldstrength and ultimate tensile strength. The yield strength at roomtemperature increased from 307 Mpa to 318 Mpa as a result of the aging.The ultimate tensile strength decreased from 720 Mpa to 710 Mpa as aresult of the high temperature aging.

TABLE 8 2.5% Cold 5% Cold 10% Cold Worked Worked Worked Annealed Agedand aged and aged and aged Yield Strength, 170 212 235 290 325 MPaUltimate Tensile 372 358 350 360 358 Strength, MPa

These characteristics may be compared to competing alloys such as 347H,which significantly lose high temperature properties as a result ofonly, for example, 10% cold work. Because fabrication of tubulars andheaters useful in an in situ heat treatment process often require coldwork for their fabrication, improvement of some high temperatureproperties, or at least lack of significant loss of high temperatureproperties may be a significant advantage for alloys having thesecharacteristics. It may be particularly advantageous when theseproperties are improved, or at least not significantly decreased, byhigh temperature aging.

Creep Example

Samples of alloys were subjected to 100 Mpa stress at 800° C. in anitrogen with about 0.1% oxygen test environment. Each of the sampleswere first annealed for one hour at 1200° C. TABLE 9 shows the time torupture, elongation at rupture, and total phase content, where the totalphase content is known.

TABLE 9 Total Phase Rupture Elongation Content % Alloy time (hr) (%) at800° C. comments B 283 7.6 4.4 B 116 5.6 4.4 B 127 3.9 4.4 10% cold workB 228 3.1 4.4 10% cold work B 185 2.3 4.4 Laser weld C 60 5.3 5.45 C 1373.6 5.45 Repeated test E 165 5.1 5.3 F 24 6.6 2.45 G 178 11.3 9.6 H 1839.8 13.46 total 7.86 good phases I 228 12.6 9.45 J 240 19.7 8.95 K 12314.2 5.62 N 147 7.4 8.85 347H 1.87 92 0.75 As received 347H 2.1 61 0.75As received NF709 56 32 Annealed NF709 30 29.4 NF709 36 26 Cold Strain10% NF709 82 30.6 Cold Strain 10% NF709 700 16.2 Cold Strain 15% NF709643 11.4 Cold Strain 20% NF709 1084 6 Cold Strain 20% NF709 754 37.6 Asreceived

A sample of the improved alloy B was processed and rolled into a tube.The seam was welded to form a 31.75 millimert (1.25 inch) OD pipe. Thepipe was then cut and welded back together in order to test the strengthof the weld. The filler metal was ERNiCrMo-3, and the weld was completedwith argon shielding gas and three passes with a preheat minimumtemperature of about 50° C. and an interpass maximum temperature ofabout 350° C. Creep failure was tested for the segment of welded pipe at44.8 MPa and 900° C. A rupture time of 41 hours was measured withfailure at a strain of 5.5%. This demonstrated that the weld, includingthe heat affected zone around the weld, was not significantly weakerthan the base alloy.

Metal Sulfidation Example

FIG. 200 depicts projected corrosion rates (metal loss per year) over aone-year period for several metals in a sulfidation atmosphere. Themetals were exposed to a gaseous mixture containing about 1% by volumecarbon monoxide sulfide (COS), about 32% by volume carbon monoxide (CO)and about 67% volume CO₂ at 538° C. (1000° F.), at 649° C. (1200° C.),at 760° C. (1400° F.), and at 871° C. (about 1600° F.) for 384 hours.The resulting data was extrapolated to a one-year time period. Theexperimental conditions simulates in situ subsurface formationsulfidation conditions of 10% H₂ by volume, 10% H₂S by volume and 25%H₂O by volume at 870° C. Curve 1428 depicts 625 stainless steel. Curve1430 depicts CF8C+ stainless steel. Curve 1432 depicts data for 410stainless steel. Curve 1434 depicts 20 25 Nb stainless steel. Curve 1436depicts 253 MA stainless steel. Curve 1438 depicts 347H stainless steel.Curve 1440. depicts 446 stainless steel. 410 stainless steel exhibits adecrease in corrosion at temperatures between about 500° C. and about650° C.

In some embodiments, cobalt is added to 410 stainless steel to decreasethe rate of corrosion at elevated temperatures (for example,temperatures greater than 1200° F.) relative to untreated 410 stainlesssteel. Addition of cobalt to 410 stainless steel may enhance thestrength of the stainless steel at high temperatures (for example,temperatures greater than 1200° F., greater than 1400° F., greater than1500° F., or greater than 1600° F.) and/or change the magneticcharacteristics of the metal. FIG. 201 depicts projected corrosion rates(metal loss per year) for 410 stainless steel and 410 stainless steelcontaining various amounts of cobalt in a sulfidation atmosphere. Themetals were exposed to the same conditions as the metals in FIG. 201.Bars 1442 depict data for 410 stainless steel. Bar 1444 depicts data for410 stainless steel with 2.5% cobalt by weight. Bar 1446 depicts datafor 410 stainless steel with 5% cobalt by weight. Bar 1448 depicts datafor 410 stainless steel with 10% cobalt by weight. As shown in FIG. 201,as the amount of cobalt in the 410 stainless steel increases, thecorrosion rate in a sulfidation atmosphere decreases relative tonon-cobalt containing 410 stainless steel in a temperature range ofabout 800° C. to about 880° C.

Varying Heater Output Simulation

A STARS simulation determined heating properties using temperaturelimited heaters with varying power outputs. FIG. 202 depicts an exampleof richness of an oil shale formation (gal/ton) versus depth (ft). Upperportions of the formation (above about 1210 feet) tend to have a leanerrichness, lower water-filled porosity, and/or less dawsonite than deeperportions of the formation. For the simulation, a heater similar to theheater depicted in FIG. 45 was used. Portion 550 had a length of 368feet above the dashed line shown in FIG. 202 and portion 548 had alength of 587 feet below the dashed line.

In the first example, the temperature limited heater had constantthermal properties along the entire length of the heater. The heaterincluded a 14.34 millimter (0.565 inch) diameter copper core with acarbon steel conductor (Curie temperature of 1418° F., pure iron withoutside diameter of 20.955 millimeter (0.825 inch)) surrounding thecopper core. The outer conductor was 347H stainless steel surroundingthe carbon steel conductor with an outside diameter of 31.75 millimeter(1.2 inch). The resistance per foot (mΩ/ft) versus temperature (° F.)profile of the heater is shown in FIG. 203. FIG. 204 depicts averagetemperature in the formation (° F.) versus time (days) as determined bythe simulation for the first example. Curve 1450 depicts averagetemperature versus time for the top portion of the formation. Curve 1452depicts average temperature versus time for the entire formation. Curve1454 depicts average temperature versus time for the bottom portion ofthe formation. As shown, the average temperature in the bottom portionof the formation lagged behind the average temperature in the topportion of the formation and the entire formation. The top portion ofthe formation reached an average temperature of 340° C. (644° F.) in1584 days. The bottom portion of the formation reached an averagetemperature of 340° C. (644° F.) in 1922 days. Thus, the bottom portionlagged behind the top portion by almost a year to reach an averagetemperature near a pyrolysis temperature.

In the second example, portion 550 of the temperature limited heater hadthe same properties used in the first example. Portion 548 of the heaterwas altered to have a Curie temperature of 843° C. (1550° F.) by theaddition of cobalt to the iron conductor. FIG. 205 depicts resistanceper foot (mΩ/ft) versus temperature (° F.) for the second heaterexample. Curve 1456 depicts the resistance profile for the top portion(portion 550). Curve 1458 depicts the resistance profile for the bottomportion (portion 548). FIG. 206 depicts average temperature in theformation (° F.) versus time (days) as determined by the simulation forthe second example. Curve 1460 depicts average temperature versus timefor the top portion of the formation. Curve 1462 depicts averagetemperature versus time for the entire formation. Curve 1464 depictsaverage temperature versus time for the bottom portion of the formation.As shown, the average temperature in the bottom portion of the formationlagged behind the average temperature in the top portion of theformation and the entire formation. The top portion of the formationreached an average temperature of 340° C. (644° F.) in 1574 days. Thebottom portion of the formation reached an average temperature of 340°C. (644° F.) in 1701 days. Thus, the bottom portion still lagged behindthe top portion to reach an average temperature near a pyrolysistemperature but the time lag was less than the time lag in the firstexample.

FIG. 207 depicts net heater energy input (Btu) versus time (days) forthe second example. Curve 1466 depicts net heater energy input for thebottom portion. Curve 1468 depicts net heater input for the top portion.The net heater energy input to reach a temperature of 340° C. (644° F.)for the bottom portion was 2.35×10¹⁰ Btu. The net heater energy input toreach a temperature of 340° C. (644° F.) for the top portion was1.32×10¹⁰ Btu. Thus, it took 12% more power to reach the desiredtemperature in the bottom portion.

FIG. 208 depicts power injection per foot (W/ft) versus time (days) forthe second example. Curve 1470 depicts power injection rate for thebottom portion. Curve 1472 depicts power injection rate for the topportion. The power injection rate for the bottom portion was about 6%more than the power injection rate for the top portion. Thus, eitherreducing the power output of the top portion and/or increasing the poweroutput of the bottom portion to a total of about 6% should provideapproximately similar heating rates in the top and bottom portions.

In the third example, dimensions of the top portion (portion 550) werealtered to provide less power output. Portion 550 was adjusted to have acopper core with an outside diameter of 13.84 millimeter (0.545 inch), acarbon steel conductor with an outside diameter of 17.78 millimeter(0.700 inch) surrounding the copper core, and an outer conductor of 347Hstainless steel with an outside diameter of 30.48 millimeter (1.2 inch)surrounding the carbon steel conductor. The bottom portion (portion 548)had the same properties as the heater in the second example. FIG. 209depicts resistance per foot (mΩ/ft) versus temperature (° F.) for thethird heater example. Curve 1474 depicts the resistance profile for thetop portion (portion 550). Curve 1476 depicts the resistance profile ofthe top portion in the second example. Curve 1478 depicts the resistanceprofile for the bottom portion (portion 548). FIG. 210 depicts averagetemperature in the formation (° F.) versus time (days) as determined bythe simulation for the third example. Curve 1480 depicts averagetemperature versus time for the top portion of the formation. Curve 1482depicts average temperature versus time for the bottom portion of theformation. As shown, the average temperature in the bottom portion ofthe formation was approximately the same as the average temperature inthe top portion of the formation, especially after a time of about 1000days. The top portion of the formation reached an average temperature of340° C. (644° F.) in 1642 days. The bottom portion of the formationreached an average temperature of 340° C. (644° F.) in 1649 days. Thus,the bottom portion reached an average temperature near a pyrolysistemperature only 5 days later than the top portion.

FIG. 211 depicts cumulative energy injection (Btu) versus time (days)for each of the three heater examples. Curve 1484 depicts cumulativeenergy injection for the first heater example. Curve 1486 depictscumulative energy injection for the second heater example. Curve 1488depicts cumulative energy injection for the third heater example. Thesecond and third heater examples have nearly identical cumulative energyinjections. The first heater example had a cumulative energy injectionabout 7% higher to reach an average temperature of 340° C. (644° F.) inthe bottom portion.

FIGS. 202-211 depict results for heaters with a 40 foot spacing betweenheaters in a triangular heating pattern. FIG. 212 depicts averagetemperature (° F.) versus time (days) for the third heater example witha 30 foot spacing between heaters in the formation as determined by thesimulation. Curve 1490 depicts average temperature versus time for thetop portion of the formation. Curve 1492 depicts average temperatureversus time for the bottom portion of the formation. The curves in FIG.212 still tracked with approximately equal heating rates in the top andbottom portions. The time to reach an average temperature in theportions was reduced. The top portion of the formation reached anaverage temperature of 340° C. (644° F.) in 903 days. The bottom portionof the formation reached an average temperature of 340° C. (644° F.) in884 days. Thus, the reduced heater spacing decreases the time needed toreach an average selected temperature in the formation.

As a fourth example, the STARS simulation was used to determine heatingproperties of temperature limited heaters with varying power outputswhen using the temperature limited heaters in the heater configurationand pattern depicted in FIGS. 65 and 67. The heater pattern had a 30foot heater spacing. Portion 550 had a length of 368 feet and portion548 had a length of 587 feet as in the previous examples. Portion 550included a solid 410 stainless steel conductor with an outside diameterof 31.75 millimeter (1.25 inch). Portion 548 included a solid 410stainless steel conductor with 9% by weight cobalt added. The Curietemperature of portion 548 is 110° C. (230° F.) higher than the Curietemperature of portion 550.

FIG. 213 depicts average temperature (° F.) versus time (days) for thefourth heater example using the heater configuration and patterndepicted in FIGS. 65 and 67 as determined by the simulation. Curve 1494depicts average temperature versus time for the top portion of theformation. Curve 1496 depicts average temperature versus time for thebottom portion of the formation. The curves in FIG. 213 showapproximately equal heating rates in the top and bottom portions. Thetop portion of the formation reached a temperature of 340° C. (644° F.)in 859 days. The bottom portion of the formation reached a temperatureof 340° C. (644° F.) in 880 days. In this heater configuration andheater pattern, the top portion of the formation reached a selectedtemperature at about the same time as a bottom portion of the formation.

Tar Sands Simulation

A STARS simulation was used to simulate heating of a tar sands formationusing the heater well pattern depicted in FIG. 98. The heaters had ahorizontal length in the tar sands formation of 600 m. The heating rateof the heaters was about 750 W/m. Production well 206B, depicted in FIG.98, was used at the production well in the simulation. The bottom holepressure in the horizontal production well was maintained at about 690kPa. The tar sands formation properties were based on Athabasca tarsands. Input properties for the tar sands formation simulation included:initial porosity equals 0.28; initial oil saturation equals 0.8; initialwater saturation equals 0.2; initial gas saturation equals 0.0; initialvertical permeability equals 250 millidarcy; initial horizontalpermeability equals 500 millidarcy; initial K_(v)/K_(h) equals 0.5;hydrocarbon layer thickness equals 28 m; depth of hydrocarbon layerequals 587 m; initial reservoir pressure equals 3771 kPa; distancebetween production well and lower boundary of hydrocarbon layer equals2.5 meter; distance of topmost heaters and overburden equals 9 meter;spacing between heaters equals 9.5 meter; initial hydrocarbon layertemperature equals 18.6° C.; viscosity at initial temperature equals 53Pa·s (53000 cp); and gas to oil ratio (GOR) in the tar equals 50standard cubic feet/standard barrel. The heaters were constant wattageheaters with a highest temperature of 538° C. at the sand face and aheater power of 755 W/m. The heater wells had a diameter of 15.2 cm.

FIG. 214 depicts a temperature profile in the formation after 360 daysusing the STARS simulation. The hottest spots are at or near heaters716. The temperature profile shows that portions of the formationbetween the heaters are warmer than other portions of the formation.These warmer portions create more mobility between the heaters andcreate a flow path for fluids in the formation to drain downwardstowards the production wells.

FIG. 215 depicts an oil saturation profile in the formation after 360days using the STARS simulation. Oil saturation is shown on a scale of0.00 to 1.00 with 1.00 being 100% oil saturation. The oil saturationscale is shown in the sidebar. Oil saturation, at 360 days, is somewhatlower at heaters 716 and production well 206B. FIG. 216 depicts the oilsaturation profile in the formation after 1095 days using the STARSsimulation. Oil saturation decreased overall in the formation with agreater decrease in oil saturation near the heaters and in between theheaters after 1095 days. FIG. 217 depicts the oil saturation profile inthe formation after 1470 days using the STARS simulation. The oilsaturation profile in FIG. 217 shows that the oil is mobilized andflowing towards the lower portions of the formation. FIG. 218 depictsthe oil saturation profile in the formation after 1826 days using theSTARS simulation. The oil saturation is low in a majority of theformation with some higher oil saturation remaining at or near thebottom of the formation in portions below production well 206B. This oilsaturation profile shows that a majority of oil in the formation hasbeen produced from the formation after 1826 days.

FIG. 219 depicts the temperature profile in the formation after 1826days using the STARS simulation. The temperature profile shows arelatively uniform temperature profile in the formation except atheaters 716 and in the extreme (corner) portions of the formation. Thetemperature profile shows that a flow path has been created between theheaters and to production well 206B.

FIG. 220 depicts oil production rate 1498 (bb1/day)(left axis) and gasproduction rate 1500 (ft³/day)(right axis) versus time (years). The oilproduction and gas production plots show that oil is produced at earlystages (0-1.5 years) of production with little gas production. The oilproduced during this time was most likely heavier mobilized oil that isunpyrolyzed. After about 1.5 years, gas production increased sharply asoil production decreased sharply. The gas production rate quicklydecreased at about 2 years. Oil production then slowly increased up to amaximum production around about 3.75 years. Oil production then slowlydecreased as oil in the formation was depleted.

From the STARS simulation, the ratio of energy out (produced oil and gasenergy content) versus energy in (heater input into the formation) wascalculated to be about 12 to 1 after about 5 years. The total recoverypercentage of oil in place was calculated to be about 60% after about 5years. Thus, producing oil from a tar sands formation using anembodiment of the heater and production well pattern depicted in FIG. 98may produce high oil recoveries and high energy out to energy in ratios.

Nanofiltration Example

A liquid sample (500 mL, 398.68 grams) was obtained from an in situ heattreatment process. The liquid sample contained 0.0069 grams of sulfurand 0.0118 grams of nitrogen per gram of liquid sample. The finalboiling point of the liquid sample was 481° C. and the liquid sample hada density of 0.8474 g/ml. The membrane separation unit used to filterthe sample was a laboratory flat sheet membrane installation type P28 asobtained from CM Celfa Membrantechnik A.G. (Switzerland). A single2-micron thick poly di-methyl siloxane membrane (GKSS ForschungszentrumGmbH, Geesthact, Germany) was used as the filtration medium. Thefiltration system was operated at 50° C. and a pressure difference overthe membrane was 10 bar. The pressure at the permeate side was nearlyatmospheric. The permeate was collected and recycled through thefiltration system to simulate a continuous process. The permeate wasblanketed with nitrogen to prevent contact with ambient air. Theretentate was also collected for analysis. During filtration the averageflux of 2 kg/m²/bar/hr did not measurably decline from an initial fluxduring the filtration. The filtered liquid (298.15 grams, 74.7%recovery) contained 0.007 grams of sulfur and 0.0124 grams of nitrogenper gram of filtered liquid; and the filtered liquid had a density of0.8459 g/ml and a final boiling point of 486° C. The retentate (56.46grams, 14.16% recovery) contained 0.0076 grams of sulfur and 0.0158grams of nitrogen per gram of retentate; and the retentate had a densityof 0.8714 g/ml and a final boiling point of 543° C.

Fouling Testing Example

The unfiltered and filtered liquid samples from the previous Examplewere tested for fouling behavior. Fouling behavior was determined usingan Alcor thermal fouling tester. The Alcor thermal fouling tester is aminiature shell and tube heat exchanger made of 1018 steel which wasgrated with Norton R222 sandpaper before use. During the test the sampleoutlet temperature, (T_(out)) was monitored while the heat-exchangertemperature (T_(c)) was kept at a constant value. If fouling occurs andmaterial is deposited on the tube surface, the heat resistance of thesample increases and consequently the outlet temperature decreases.Hence the decrease in outlet temperature after a given period of time isa measure of fouling severity. The temperature decrease after two hoursof operation is used as fouling severity indicator.ΔT=T_(out(o))−T_(out(2h)). T_(out(o)) is define as the maximum (stable)outlet temperature obtained at the start of the test, T_(out(2h)) isrecorded 2 hours after the first noted decrease of the outlettemperature or when the outlet temperature has been stable for at least2 hours.

During each test, the liquid sample was continuously circulated throughthe heat exchanger at approximately 3 mL/min. The residence time in theheat exchanger was about 10 seconds. The operating conditions were asfollows: 40 bar of pressure, T_(sample) was about 50° C., T_(c) was 350°C., test time was 4.41 hours. The ΔT for the unfiltered liquid streamsample was 15° C. The ΔT for the filtered sample was zero.

This example demonstrates that nanofiltration of a liquid streamproduced from an in situ heat treatment process removes at least aportion of clogging compositions.

Olefin Production Example

An experimental pilot system was used to conduct the experiments. Thepilot system included a feed supply system, a catalyst loading andtransfer system, a fast fluidized riser reactor, a stripper, a productseparation and collecting system, and a regenerator. The riser reactorwas an adiabatic riser having an inner diameter of from 11 mm to 19 mmand a length of about 3.2 m. The riser reactor outlet was in fluidcommunication with the stripper that was operated at the sametemperature as the riser reactor outlet flow and in a manner to provideessentially 100 percent stripping efficiency. The regenerator was amulti-stage continuous regenerator used for regenerating the spentcatalyst. The spent catalyst was fed to the regenerator at a controlledrate and the regenerated catalyst was collected in a vessel. Materialbalances were obtained during each of the experimental runs at 30-minuteintervals. Composite gas samples were analyzed by use of an on-line gaschromatograph and the liquid product samples were collected and analyzedovernight. The coke yield was measured by measuring the catalyst flowand by measuring the delta coke on the catalyst as determined bymeasuring the coke on the spent and regenerated catalyst samples takenfor each run when the unit was operating at steady state.

A liquid stream produced from an in situ heat treatment process wasfractioned to obtain a vacuum gas oil (VGO) stream having a boilingrange distribution from 310° C. to 640° C. The VGO stream was contactedwith a fluidized catalytic cracker E-Cat containing 10% ZSM-5 additivein the catalytic system described above. The riser reactor temperaturewas maintained at 593° C. (1100° F.). The product produced contained,per gram of product, 0.1402 grams of C₃ olefins, 0.137 grams of C₄olefis, 0.0897 grams of C₅ olefins, 0.0152 grams of iso-C₅ olefins,0.0505 grams isobutylene, 0.0159 grams of ethane, 0.0249 grams ofisobutane, 0.0089 grams of n-butane, 0.0043 grams pentane, 0.0209 gramsiso-pentane, 0.2728 grams of a mixture of C₆ hydrocarbons andhydrocarbons having a boiling point of at most 232° C. (450° F.), 0.0881grams of hydrocarbons having a boiling range distribution between 232°C. and 343° C. (between 450° F. and 650° F.), 0.0769 grams ofhydrocarbons having a boiling range distribution between 343° C. and399° C. (650° F. and 750° F.) and 0.0386 grams of hydrocarbons having aboiling range distribution of at least 399° C. (750° F.) and 0.0323grams of coke.

This example demonstrates a method of producing crude product byfractionating liquid stream produced from separation of the liquidstream from the formation fluid to produce a crude product having aboiling point above 343° C.; and catalytically cracking the crudeproduct having the boiling point above 343° C. to produce one or moreadditional crude products, wherein least one of the additional crudeproducts is a second gas stream.

Production of Olefins from A Liquid Stream Example

A thermally cracked naphtha was used to simulate a liquid streamproduced from an in situ heat treatment process having a boiling rangedistribution from 30° C. to 182° C. The naphtha contained, per gram ofnaphtha, 0.186 grams of naphthenes, 0.238 grams of isoparaffins, 0.328grams of n-paraffins, 0.029 grams cyclo-olefins, 0.046 grams ofiso-olefins, 0.064 grams of n-olefins and 0.109 grams of aromatics. Thenaphtha stream was contacted with a FCC E-Cat with 10% ZSM-5 additive inthe catalytically cracking system described above to produce a crudeproduct. The riser reactor temperature was maintained at 593° C. (1100°F.). The crude product included, per gram of crude product, 0.1308 gramsethylene, 0.0139 grams of ethane, 0.0966 grams C4-olefis, 0.0343 gramsC4 iso-olefins, 0.0175 grams butane, 0.0299 grams isobutane, 0.0525grams C5 olefis, 0.0309 grams C5 iso-olefins, 0.0442 grams pentane,0.0384 grams iso-pentane, 0.4943 grams of a mixture of C₆ hydrocarbonsand hydrocarbons having a boiling point of at most 232° C. (450° F.),0.0201 grams of hydrocarbons having a boiling range distribution between232° C. and 343° C. (between 450° F. and 650° F.), 0.0029 grams ofhydrocarbons having a boiling range distribution between 343° C. and399° C. (650° F. and 750° F.) and 0.00128 grams of hydrocarbons having aboiling range distribution of at least 399° C. (750° F.) and 0.00128grams of coke. The total amount of C₃-C₅ olefins was 0.2799 grams pergram of naphtha.

This example demonstrates a method of producing crude product byfractionating liquid stream produced from separation of the liquidstream from the formation fluid to produce a crude product having aboiling point above 343° C.; and catalytically cracking the crudeproduct having the boiling point above 343° C. to produce one or moreadditional crude products, wherein least one of the additional crudeproducts is a second gas stream.

In this patent, certain U.S. patents, U.S. patent applications, andother materials (for example, articles) have been incorporated byreference. The text of such U.S. patents, U.S. patent applications, andother materials is, however, only incorporated by reference to theextent that no conflict exists between such text and the otherstatements and drawings set forth herein. In the event of such conflict,then any such conflicting text in such incorporated by reference U.S.patents, U.S. patent applications, and other materials is specificallynot incorporated by reference in this patent.

Further modifications and alternative embodiments of various aspects ofthe invention may be apparent to those skilled in the art in view ofthis description. Accordingly, this description is to be construed asillustrative only and is for the purpose of teaching those skilled inthe art the general manner of carrying out the invention. It is to beunderstood that the forms of the invention shown and described hereinare to be taken as the presently preferred embodiments. Elements andmaterials may be substituted for those illustrated and described herein,parts and processes may be reversed, and certain features of theinvention may be utilized independently, all as would be apparent to oneskilled in the art after having the benefit of this description of theinvention. Changes may be made in the elements described herein withoutdeparting from the spirit and scope of the invention as described in thefollowing claims. In addition, it is to be understood that featuresdescribed herein independently may, in certain embodiments, be combined.

1. A system for treating a hydrocarbon containing formation, comprising:a steam and electricity cogeneration facility; at least one injectionwell located in a first portion of the formation, the injection wellconfigured to provide steam from the steam and electricity cogenerationfacility to the first portion of the formation; at least one productionwell located in the first portion of the formation, the production wellconfigured to produce first hydrocarbons; at least one electrical heaterlocated in a second portion of the formation, at least one of theelectrical heaters configured to be powered by electricity from thesteam and electricity cogeneration facility; at least one productionwell located in the second portion of the formation, the production wellconfigured to produce second hydrocarbons; and the steam and electricitycogeneration facility being configured to use at least a portion of thefirst hydrocarbons and/or the second hydrocarbons to generateelectricity, wherein at least a portion of the generated electricity ismade in one or more generators, and at least some exhaust heat from atleast one of the generators is configured to be used to make steam. 2.The system of claim 1, wherein the steam and electricity cogenerationfacility is configured to use hydrocarbons to make steam.
 3. The systemof claim 1, wherein at least a portion of the first hydrocarbons have anAPI gravity of at most about 15°.
 4. The system of claim 1, wherein atleast a portion of the second hydrocarbons have an API gravity of atleast about 20°.
 5. The system of claim 1, wherein the system isconfigured to mix at least a portion of the first hydrocarbons and atleast a portion of the second hydrocarbons.
 6. The system of claim 1,wherein the system is configured to vary the amount of electricitygenerated and the amount of steam made to vary the production of atleast a portion of the first hydrocarbons and/or the secondhydrocarbons.
 7. The system of claim 1, wherein the system furthercomprises a treatment facility for treating at least a portion of thefirst hydrocarbons and/or second hydrocarbons before use in the steamand electricity cogeneration facility.
 8. The system of claim 1, whereinthe steam and electricity cogeneration facility is configured to bumboth gaseous and liquid hydrocarbons.
 9. The system of claim 1, whereinthe first and second portions are separated from each other by a barrieror by a substantially impermeable zone of the formation.
 10. The systemof claim 1, wherein the formation comprises different layers atdifferent depths.
 11. The system of claim 1, wherein the first portionis at a depth that is different from the second portion, and wherein thefirst portion comprises different initial hydrocarbon properties thanthe second portion.
 12. A method for treating a hydrocarbon containingformation, comprising: providing steam to a first portion of theformation; producing at least some first hydrocarbons from the firstportion of the formation; providing heat from one or more electricalheaters to a second portion of the formation; allowing the provided heatto transfer from the heaters to the second portion of the formation;producing at least some second hydrocarbons from the second portion ofthe formation; using at least a portion of the first hydrocarbons and/orthe second hydrocarbons in a steam and electricity generation facility,wherein the facility provides steam to the first portion of theformation and electricity for at least some of the heaters; and using atleast a portion of the second hydrocarbons as a gas for one or moreadditional heaters in the formation, wherein at least one of theadditional heaters is configured to combust the gas.
 13. The method ofclaim 12, further comprising using at least a portion of the firsthydrocarbons and/or the second hydrocarbons to make electricity in oneor more generators, and using at least some exhaust from at least one ofthe generators to make steam.
 14. The method of claim 12, furthercomprising burning at least a portion of the first hydrocarbons and/orat least a portion of the second hydrocarbons to make steam.
 15. Themethod of claim 12, wherein at least a portion of the first hydrocarbonshave an API gravity of at most about 15°.
 16. The method of claim 12,wherein at least a portion of the second hydrocarbons have an APIgravity of at least about 20°.
 17. The method of claim 12, furthercomprising mixing at least a portion of the first hydrocarbons and atleast a portion of the second hydrocarbons.
 18. The method of claim 12,further comprising mixing at least a portion of the first hydrocarbonsand at least a portion of the second hydrocarbons to make a fuel forelectrical generators.
 19. The method of claim 12, further comprisingusing all of the first hydrocarbons and/or the second hydrocarbons asfuel for generating electricity and/or to make steam.
 20. The method ofclaim 12, further comprising varying the amount of electricity generatedand the amount of steam made to vary the production of the firsthydrocarbons and/or the second hydrocarbons.
 21. The method of claim 12,further comprising providing steam to the second portion prior toproviding heat from the electrical heaters.
 22. The method of claim 12,further comprising producing a transportation fuel from at least some ofthe first and/or the second hydrocarbons.
 23. A method for treating ahydrocarbon containing formation, comprising: providing steam to a firstportion of the formation; providing heat from one or more electricalheaters to the first portion of the formation; producing firsthydrocarbons and/or second hydrocarbons from the first portion of theformation; providing heat from one or more electrical heaters to asecond portion of the formation; allowing the provided heat to transferfrom the heaters to the second portion of the formation; producingsecond hydrocarbons from the second portion of the formation; and usingthe first hydrocarbons and/or the second hydrocarbons in a steam andelectricity generation facility, wherein the facility provides steam tothe first portion of the formation and electricity for at least some ofthe heaters.
 24. The method of claim 23, further comprising using atleast a portion of the first hydrocarbons and/or at least a portion ofthe second hydrocarbons to make electricity.
 25. The method of claim 23,further comprising using at least a portion of the first hydrocarbonsand/or at least a portion of the second hydrocarbons to make steam. 26.The method of claim 23, wherein at least a portion of the firsthydrocarbons have an API gravity of at most about 15°.
 27. The method ofclaim 23, wherein at least a portion of the second hydrocarbons have anAPI gravity of at least about 20°.
 28. The method of claim 23, furthercomprising varying the amount of electricity generated and the amount ofsteam made to vary the production of the first hydrocarbons and/or thesecond hydrocarbons.
 29. The method of claim 23, further comprisingallowing heat and/or hydrocarbons to transfer between the first and thesecond portions.
 30. The method of claim 23, further comprisingproducing a transportation fuel from at least some of the first and/orthe second hydrocarbons.
 31. A method for treating a hydrocarboncontaining formation, comprising: providing steam to a first portion ofthe formation; producing first hydrocarbons from the first portion ofthe formation; providing heat from one or more electrical heaters to asecond portion of the formation; allowing the provided heat to transferfrom the heaters to the second portion of the formation; providing steamto the second portion of the formation; producing first hydrocarbonsand/or second hydrocarbons from the second portion of the formation;using the first hydrocarbons and/or the second hydrocarbons in a steamand electricity generation facility, wherein the facility provides steamto the first portion or the second portion of the formation andelectricity for at least some of the heaters; and providing heat fromone or more electrical heaters to the first portion of the formation,and producing first hydrocarbons and/or second hydrocarbons from thefirst portion of the formation.
 32. The method of claim 31, furthercomprising using at least a portion of the first hydrocarbons and/or atleast a portion of the second hydrocarbons to make electricity.
 33. Themethod of claim 31, further comprising using at least a portion of thefirst hydrocarbons and/or at least a portion of the second hydrocarbonsto make steam.
 34. The method of claim 31, wherein at least a portion ofthe first hydrocarbons have an API gravity of at most about 15°.
 35. Themethod of claim 31, wherein at least a portion of the secondhydrocarbons have an API gravity of at least about 20°.
 36. The methodof claim 31, further comprising varying the amount of electricitygenerated and the amount of steam made to vary the production of thefirst hydrocarbons and/or the second hydrocarbons.
 37. The method ofclaim 31, further comprising allowing heat and/or hydrocarbons totransfer between the first and the second portions.
 38. The method ofclaim 31, further comprising producing a transportation fuel from atleast some of the first and/or the second hydrocarbons.
 39. A system fortreating a hydrocarbon containing formation, comprising: a steam andelectricity cogeneration facility; at least one injection well locatedin a first portion of the formation, the injection well configured toprovide steam from the steam and electricity cogeneration facility tothe first portion of the formation; at least one production well locatedin the first portion of the formation, the production well configured toproduce first hydrocarbons; at least one electrical heater located in asecond portion of the formation, at least one of the electrical heatersconfigured to be powered by electricity from the steam and electricitycogeneration facility; at least one production well located in thesecond portion of the formation, the production well configured toproduce second hydrocarbons; wherein the first and second portions areseparated from each other by a barrier or by a substantially impermeablezone of the formation; and the steam and electricity cogenerationfacility is configured to use at least a portion of the firsthydrocarbons and/or the second hydrocarbons to generate electricity. 40.A system for treating a hydrocarbon containing formation, comprising: asteam and electricity cogeneration facility; at least one injection welllocated in a first portion of the formation, the injection wellconfigured to provide steam from the steam and electricity cogenerationfacility to the first portion of the formation; at least one productionwell located in the first portion of the formation, the production wellconfigured to produce first hydrocarbons; at least one electrical heaterlocated in a second portion of the formation, at least one of theelectrical heaters configured to be powered by electricity from thesteam and electricity cogeneration facility; at least one productionwell located in the second portion of the formation, the production wellconfigured to produce second hydrocarbons; wherein the first portion isat a depth that is different from the second portion, and the firstportion comprises different initial hydrocarbon properties than thesecond portion; and the steam and electricity cogeneration facility isconfigured to use at least a portion of the first hydrocarbons and/orthe second hydrocarbons to generate electricity.